August 12, 2025 - 10-Q: Quarterly report [Sections 13 or 15(d)]

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_________________________

FORM 10-Q

_________________________

(Mark One)


x			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2025


o			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 001-42282

_________________________

BKV CORPORATION

(Exact name of registrant as specified in its charter)

_________________________


Delaware						85-0886382
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

1200 17th Street, Suite 2100 Denver, Colorado						80202
(Address of Principal Executive Offices)						(Zip Code)

(720) 375-9680

Registrant’s telephone number, including area code

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, $0.01 Par Value	BKV	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes o No x

As of August 8, 2025, 84,711,220 shares of the registrant's common stock were outstanding.

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Glossary of Commonly Used Terms

Cautionary Note Regarding Forward-Looking Statements

PART I FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

Condensed Consolidated Balance Sheets			11

Condensed Consolidated Statements of Operations			12

Condensed Consolidated Statements of Cash Flows			13

Condensed Consolidated Statements of Stockholders' Equity and Mezzanine Equity			15

Notes to the Condensed Consolidated Financial Statements			17

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			36

Item 3. Quantitative and Qualitative Disclosures About Market Risk			53

Item 4. Controls and Procedures			54

PART II OTHER INFORMATION

Item 1. Legal Proceedings			56

Item 1A. Risk Factors			56

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			56

Item 3. Defaults Upon Senior Securities			56

Item 4. Mine Safety Disclosures			56

Item 5. Other Information			57

Item 6. Exhibits			58

Signatures			59

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Glossary of Commonly Used Terms

The definitions set forth below include indicated terms in this Quarterly Report on Form 10-Q. All natural gas referred to in this Quarterly Report are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit.

“ABR” refers to the alternative borrowing rate.

“Banpu” refers to our sponsor, Banpu Public Company Limited, a public company listed on the Stock Exchange of Thailand and the ultimate parent company of BKV Corporation, BNAC, Banpu Power, and BPPUS.

“Banpu Power” refers to Banpu Power Public Company Limited, a public company listed on the Stock Exchange of Thailand. Banpu owns approximately 75.4% of Banpu Power as of June 30, 2025.

“Barnett” refers to the Barnett Shale in the Fort Worth Basin of Texas.

“Barnett Zero Project” refers to BKV dCarbon Barnett Zero, LLC, a Delaware limited liability company and, as of May 8, 2025, a wholly-owned subsidiary of the BKV-CIP Joint Venture.

“Bbl” refers to one stock tank barrel, of 42 U.S. gallons liquid volume, used in this Quarterly Report on Form 10-Q in reference to crude oil or other liquid hydrocarbons.

“Bcf” refers to one billion cubic feet of natural gas or CO2.

“Bcfe” refers to one billion cubic feet of natural gas equivalent.

“BKV dCarbon Ventures” refers to BKV dCarbon Ventures, LLC, a Delaware limited liability company and the CCUS business of BKV Corporation.

“BKV Upstream Midstream” refers to BKV Upstream Midstream, LLC, a Delaware limited liability company and wholly-owned subsidiary of BKV Corporation.

“BKV-BPP Cotton Cove” or “BKV-BPP Cotton Cove Joint Venture” refers to BKV-BPP Cotton Cove, LLC, a Delaware limited liability company and the joint venture between BKV dCarbon Ventures and BPPUS, in which we own an indirect 51% interest.

“BKV-BPP Power” or “BKV-BPP Power Joint Venture” refers to BKV-BPP Power, LLC, a Delaware limited liability company and the joint venture between BKV Corporation and BPPUS, in which we own a 50% interest.

“BKV-CIP Joint Venture” refers to BKV dCarbon Project, LLC, a Delaware limited liability company and the joint venture between BKV dCarbon Ventures and C Squared Solutions, Inc., in which we own a 51% interest.

“BKV-CIP JV Agreement” refers to the Limited Liability Company Agreement of BKV dCarbon Project, LLC, entered into on May 8, 2025, by BKV dCarbon Ventures, C Squared Solutions, Inc. and, for the limited purposes specified therein, BKV Corporation.

“BNAC” refers to Banpu North America Corporation, a subsidiary of Banpu, our sponsor, and the majority stockholder of BKV Corporation.

“BPPUS” refers to Banpu Power US Corporation, a wholly-owned subsidiary of Banpu Power and the owner of a 50% interest in the BKV-BPP Power Joint Venture and a 49% interest in the BKV-BPP Cotton Cove Joint Venture.

“Btu” refers to British thermal unit, which is the heat required to raise the temperature of one pound of liquid water by one degree Fahrenheit.

“Carbon Sequestered Gas” refers to a Scope 1, 2, and 3 carbon neutral natural gas product.

“CCUS” refers to carbon capture, utilization, and sequestration.

“Chaffee” refers to BKV Chaffee Corners, LLC, a Delaware limited liability company and, prior to its sale on June 14, 2024, a wholly-owned subsidiary of BKV Corporation.

“Chelsea” refers to BKV Chelsea, LLC, a Delaware limited liability company and wholly-owned subsidiary of BKV Corporation.

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“Class B Member” refers to C Squared Solutions, Inc.

“CO2” refers to carbon dioxide.

“CO2e” refers to carbon dioxide equivalent.

“Code” means the Internal Revenue Code of 1986, as amended.

“developed reserves” are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well or (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“Devon Barnett Acquisition” refers to our acquisition of more than 289,000 net acres, 3,850 producing operated wells and related upstream assets in the Barnett from Devon Energy Corporation, which closed in October 2020.

“Eagle Ford Project” refers to BKV dCarbon Las Tiendas, LLC, a Delaware limited liability company and, as of May 8, 2025, a wholly-owned subsidiary of the BKV-CIP Joint Venture.

“ERCOT” refers to the Electric Reliability Council of Texas.

“ESG” refers to environmental, social, and governance.

“Exxon Barnett Acquisition” refers to our acquisition of approximately 165,000 net acres, 2,100 operated wells and related natural gas upstream, midstream and other assets in the Barnett from XTO Energy, Inc. and Barnett Gathering LLC, subsidiaries of Exxon Mobil Corporation, which closed on June 30, 2022.

“GAAP” refers to generally accepted accounting principles in the United States.

“GHG” refers to greenhouse gases.

“HRCO” refers to a contract for the financial purchase and sale of power based on a floating price of natural gas at a predetermined location using a predetermined conversion factor, or heat rate, required to turn the fuel input into electricity.

“LNG” refers to liquefied natural gas.

“MBbls” refers to one thousand barrels of crude oil or other liquid hydrocarbons.

“Mcf” refers to one thousand cubic feet.

“Mcf/d” refers to one thousand cubic feet per day.

“Mcfe” refers to one thousand cubic feet of natural gas equivalent.

“MMBtu” refers to one million British thermal units, which is the heat required to raise the temperature of one pound of liquid water by one degree Fahrenheit.

“MMcf” refers to one million cubic feet.

“MMcf/d” refers to one million cubic feet per day.

“MMcfe” refers to one million cubic feet of natural gas equivalent, calculated by converting barrels of crude oil or other liquid hydrocarbons to natural gas at a ratio of one Bbl to six Mcf of natural gas. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

“MMcfe/d” refers to one million cubic feet of natural gas equivalent per day.

“NEPA” refers to the Marcellus Shale in the Appalachian Basin of Northeast Pennsylvania.

“net acres” refers to the percentage of total acres an owner has out of a particular number of acres, or a specified tract. For example, an owner who has 50% interest in 100 acres owns 50 net acres.

“net zero” refers to the full elimination and/or offset of Scope 1, Scope 2, and/or Scope 3 emissions, as applicable, from our owned and operated upstream businesses.

“NGL” refers to natural gas liquids.

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“NYMEX” refers to the New York Mercantile Exchange.

“OPEC” refers to the Organization of the Petroleum Exporting Countries.

“OPIS” refers to a Dow Jones Company that surveys and collects price information and publishes benchmarks for various energy commodities.

“Pad of the Future” refers to our program of converting natural gas-powered instrument pneumatics to compressed air or electric power instruments on existing pads, combined with emission and leak surveys.

“proved developed producing reserves” or “PDP reserves” refers to quantities of proved developed reserves expected to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

“proved reserves” refers to quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (“LKH”) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined an HKO elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (a) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (b) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

“RBL Credit Agreement” refers to that certain reserve-based lending agreement dated as of June 11, 2024, among BKV Corporation, BKV Upstream Midstream, Citibank, N.A., as administrative agent, and the financial institutions party thereto.

“Revolving Credit Agreement” refers to $100.0 million of commitments of unsecured revolving loans with Bangkok Bank Public Company Limited (New York Branch).

“Revolving Credit Facilities” refers to an uncommitted credit facilities with Oversea Chinese Banking Corporation and Standard Chartered Bank of up to $55.0 million and $50.0 million, respectively.

“Scope 1 emissions” refers to direct GHG emissions that occur from sources that are controlled or owned by an organization.

“Scope 2 emissions” refers to indirect GHG emissions associated with the purchase of electricity, steam, heat or cooling.

“Scope 3 emissions” refers to GHG emissions that result from the end use of an organization’s products, as estimated per Category 11 (Use of Sold Product), as well as emissions from other business activities from assets not owned or controlled by the organization but that the organization indirectly impacts in its value chain.

“Section 45I tax credits” refers to tax credits provided under Section 45I of the Code.

“Section 45Q tax credits” refers to tax credits provided under Section 45Q of the Code.

“SOFR” refers to the secured overnight financing rate.

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“Temple I” refers to the combined gas turbine and steam turbine power plant located in Temple, Texas and owned by the BKV-BPP Power Joint Venture.

“Temple II” refers to a second combined gas turbine and steam turbine power plant located in Temple, Texas, which power plant sits on the same site as Temple I and is owned by the BKV-BPP Power Joint Venture.

“Temple Plants” refers to Temple I and Temple II, collectively.

“Term Loan Credit Agreement” refers to a credit agreement with a syndicate of banks and Bangkok Bank Public Company Limited (New York Branch), as the administrative agent, which included $600.0 million of commitments for term loans used to solely to fund a portion of the purchase price for the Exxon Barnett Acquisition.

“undeveloped reserves” are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

“working interest” refers to the right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical fact contained in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenue and losses, projected costs, prospects, plans and objectives of management and dividend policy, are forward-looking statements. When used in this Quarterly Report on Form 10-Q, words such as “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “seek,” “envision,” “forecast,” “target,” “predict,” “may,” “should,” “would,” “could,” “will,” the negative of these terms and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Such forward-looking statements include, but are not limited to, statements about the consummation and timing of the Bedrock acquisition, the anticipated benefits, opportunities and results with respect to the acquisition, including any expected value creation, reserves additions, midstream opportunities and other anticipated impacts from the Bedrock acquisition, as well as other aspects of the transaction, guidance, projected or forecasted financial and operating results, future liquidity, leverage, results in certain basins, objectives, project timing, expectations and intentions, regulatory and governmental actions and other statements that are not historical facts. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events.

Forward-looking statements contained in this Quarterly Report on Form 10-Q include, but are not limited to, statements about:

•our business strategy;

•our reserves;

•our financial strategy, liquidity, and capital required for our development programs;

•our relationship with Banpu, including future agreements with Banpu;

•actual and potential conflicts of interest relating to Banpu, its affiliates, and other entities in which members of our officers and directors are or may become involved;

•volatility in natural gas, NGL, and oil prices;

•our dividend policy;

•our drilling plans and the timing and amount of future production of natural gas, NGL, and oil;

•our hedging strategy and results;

•competition and government regulation;

•changes in trade regulation, including tariffs and other market factors;

•legal, regulatory, or environmental matters;

•marketing of natural gas, NGL, and oil;

•business or leasehold acquisitions and integration of acquired businesses, including the Bedrock acquisition, with our business;

•our ability to develop existing prospects;

•costs of developing our properties and of conducting our operations;

•our plans to establish midstream contracts that allow us to supply our own natural gas directly to the Temple Plants;

•our plan to continue to build out our power generation business and to expand into retail power;

•our ability to develop, produce, and sell Carbon Sequestered Gas;

•our ability to effectively operate and grow our CCUS business;

•our ability to forecast annual CO2e sequestration rates for our CCUS projects;

•our ability to reach final investment decision and execute and complete any of our pipeline of identified CCUS projects;

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•our ability to identify and complete additional CCUS projects as we expand our upstream operations;

•our ability to effectively operate and grow our retail power business;

•our anticipated Scope 1, 2, and 3 emissions from our owned and operated upstream and natural gas midstream businesses and our sustainability plans and goals, including our plans to offset our Scope 1, 2, and 3 emissions from our owned and operated upstream and natural gas midstream businesses;

•our ESG strategy and initiatives, including those relating to the generation and marketing of environmental attributes or new products seeking to benefit from ESG-related activities, and the continuation of government tax incentives applicable thereto;

•the impact of regional epidemics or pandemics and its effects on our business and financial condition;

•general economic conditions;

•cost inflation;

•credit markets;

•our ability to service our indebtedness;

•our ability to expand our business, including through the recruitment and retention of skilled personnel;

•our future operating results;

•the remediation of our material weaknesses;

•the Bedrock acquisition and the anticipated timing and benefits thereof;

•the impact of the One Big Beautiful Bill Act of 2025 (the “OBBBA”); and

•our plans, objectives, expectations, and intentions.

When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2024 (“2024 Annual Report on Form 10-K”). These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Any forward-looking statement speaks only as of the date on which such statement is made. We undertake no obligation to update any forward-looking statements made in this Quarterly Report on Form 10-Q to reflect events or circumstances after the date of this Quarterly Report on Form 10-Q or to reflect new information or the occurrence of unanticipated events, except as required by law.

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PART I FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

BKV Corporation

Condensed Consolidated Balance Sheets
(in thousands)

(Unaudited)

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	June 30, 2025		December 31, 2024
Assets
Current assets
Cash and cash equivalents	$	21,426	$	14,868

Accounts receivable, net	47,948		54,435
Accounts receivable, related parties	11,611		11,414

Prepaid expenses	4,435		7,638
Inventory	6,960		6,255
Commodity derivative assets, current	556		—

Asset held for sale	5,500		—

Total current assets	98,436		94,610
Natural gas properties
Developed properties	2,430,788		2,315,167
Undeveloped properties	10,739		10,757
Midstream assets	276,811		276,644
Accumulated depreciation, depletion, and amortization	(780,001)		(714,287)
Total natural gas properties, net	1,938,337		1,888,281
Other property and equipment, net	104,253		97,300


Goodwill	18,417		18,417
Investment in BKV-BPP Power	114,676		115,173


Commodity derivative assets	6,622		—
Other noncurrent assets	23,686		17,307
Total assets	$	2,304,427	$	2,231,088

Liabilities, mezzanine equity, and stockholders' equity
Current liabilities
Accounts payable and accrued liabilities	$	123,802	$	121,366

Contingent consideration payable	—		20,000


Commodity derivative liabilities, current	44,011		20,277
Income taxes payable to related party	2,265		1,438



Other current liabilities	4,653		3,124
Total current liabilities	174,731		166,205
Asset retirement obligations	204,331		198,795


Commodity derivative liabilities	45,645		47,357


Deferred tax liability, net	86,565		88,688
Long-term debt, net	200,000		165,000
Other noncurrent liabilities	5,097		5,469
Total liabilities	716,369		671,514
Commitments and contingencies (Note 11)
Mezzanine equity
Noncontrolling interest	(2,073)		—
Stockholders' equity
Common stock, $0.01 par value; 500,000 authorized shares; 84,711 and 84,600 shares issued and outstanding as of June 30, 2025 and December 31, 2024, respectively	1,513		1,512
Treasury stock, shares at cost; 214 shares and 214 shares as of June 30, 2025 and December 31, 2024, respectively	(6,663)		(6,663)
Additional paid-in capital	1,452,602		1,447,671
Retained earnings	142,679		117,054
Total stockholders' equity	1,590,131		1,559,574
Total liabilities, mezzanine equity, and stockholders' equity	$	2,304,427	$	2,231,088


The accompanying notes are an integral part of these condensed consolidated financial statements.			11

BKV Corporation

Condensed Consolidated Statements of Operations
(in thousands, except per share amounts)

(Unaudited)

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	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Revenues and other operating income
Natural gas, NGL, and oil sales	$	199,729	$	125,854	$	415,855	$	267,541
Midstream revenues	2,739		3,378		5,510		7,506
Derivative gains (losses), net	112,208		(7,486)		(39,983)		(11,165)
Marketing revenues	1,372		2,046		7,857		6,967
Gain on sale of business	—		5,968		—		5,968



Section 45Q tax credits	2,574		3,644		5,881		5,973
Related party revenues	425		1,101		851		2,203
Other	2,997		1,693		4,893		3,119
Total revenues and other operating income	322,044		136,198		400,864		288,112
Operating expenses
Lease operating and workover	34,176		34,172		69,231		68,640
Taxes other than income	13,404		9,850		23,626		21,215
Gathering and transportation	63,026		53,714		118,819		113,105
Depreciation, depletion, amortization, and accretion	38,044		59,313		78,014		111,479
General and administrative	30,516		19,296		55,773		39,941
Other	14,480		3,034		20,706		11,276
Total operating expenses	193,646		179,379		366,169		365,656
Income (loss) from operations	128,398		(43,181)		34,695		(77,544)
Other income (expense)
Gains (losses) on contingent consideration liabilities	—		(524)		—		6,070
Earnings (losses) from equity affiliate	9,088		(15,253)		(497)		(22,960)
Loss on early extinguishment of debt	—		(13,877)		—		(13,877)
Interest expense	(5,458)		(15,163)		(10,510)		(31,246)
Interest expense, related party	—		(1,879)		—		(3,852)
Interest income	162		1,771		311		3,404
Other income	440		15		776		350
Income (loss) before income taxes	132,630		(88,091)		24,775		(139,655)
Income tax benefit (expense)	(27,895)		28,394		1,294		41,373
Net income (loss)	104,735		(59,697)		26,069		(98,282)
Less: net income (loss) attributable to noncontrolling interest	163		—		163		—
Net income (loss) attributable to BKV	$	104,572	$	(59,697)	$	25,906	$	(98,282)

Net income (loss) per common share attributable to BKV:
Basic	$	1.23	$	(0.90)	$	0.30	$	(1.48)
Diluted	$	1.23	$	(0.90)	$	0.30	$	(1.48)

Weighted average number of common shares outstanding:
Basic	84,710		66,349		84,708		66,318
Diluted	84,834		66,349		84,789		66,318


The accompanying notes are an integral part of these condensed consolidated financial statements.			12

BKV Corporation

Condensed Consolidated Statements of Cash Flows
(in thousands)

(Unaudited)

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	Six Months Ended June 30,
	2025		2024
Cash flows from operating activities:
Net income (loss)	$	26,069	$	(98,282)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization, and accretion	78,201		111,650
Equity-based compensation expense	6,136		2,145
Deferred income tax benefit	(2,123)		(41,800)
Unrealized losses on derivatives, net	31,050		79,100
Gains on contingent consideration liabilities	—		(6,070)
Settlement of contingent consideration	(20,000)		(20,000)
Proceeds from the sale of call options	—		23,502
Payments for the purchase of put options	(16,206)		—
Gain on sale of business	—		(5,968)
Gains on sales of assets	(1,208)		(816)

Transaction costs from sale of business	—		(3,461)
Impairment of asset held for sale	2,446		—
Losses from equity affiliate	497		22,960
Loss on early extinguishment of debt	—		13,877
Other, net	2,986		1,341
Changes in operating assets and liabilities:
Accounts receivable, net	6,487		(11,756)
Accounts receivable, related party	(197)		(7,231)



Accounts payable and accrued liabilities	(17,539)		(48,891)





Other changes in operating assets and liabilities	2,184		(518)
Net cash provided by operating activities	98,783		9,782
Cash flows from investing activities:



Capital expenditures	(123,669)		(31,608)
Deposit on fixed asset purchase	(7,500)		—
Proceeds from sale of business	—		131,708
Proceeds from sales of assets	1,258		1,556


Other investing activities, net	257		(23)
Net cash provided by (used in) investing activities	(129,654)		101,633
Cash flows from financing activities:



Payments on notes payable to related party	—		(25,000)
Proceeds under RBL Credit Agreement	355,000		425,000
Payments on RBL Credit Agreement	(320,000)		(65,000)
Payment on term loan agreement	—		(456,000)
Payment of debt issuance costs	(720)		(8,054)
Proceeds from draws on credit facilities	—		44,000
Payments on credit facilities	—		(171,000)
Payments of deferred offering costs	—		(1,020)
Debt extinguishment costs	—		(10,213)

Net share settlements, equity-based compensation	(1,204)		—
Cash contributions from noncontrolling interest	4,353		—
Net cash provided by (used in) financing activities	37,429		(267,287)
Net increase (decrease) in cash, cash equivalents, and restricted cash	6,558		(155,872)
Cash, cash equivalents, and restricted cash, beginning of period	14,868		165,069
Cash and cash equivalents, end of period	$	21,426	$	9,197


The accompanying notes are an integral part of these condensed consolidated financial statements.			13

BKV Corporation

Condensed Consolidated Statements of Cash Flows
(in thousands)

(Unaudited)

Table of Contents


	Six Months Ended June 30,
Supplemental cash flow information:	2025		2024
Cash payments for:
Interest	$	9,010	$	44,414
Income tax	$	197	$	6
Non-cash investing and financing activities:



Increase in accrued capital expenditures	$	13,105	$	1,296
Additions to asset retirement obligations	$	80	$	21
Lease liabilities arising from obtaining right-of-use assets	$	—	$	494
Decrease in accrued offering costs	$	—	$	(341)
Adjustment of minority ownership puttable shares to redemption value	$	—	$	488
Adjustment of equity-based compensation to redemption value	$	—	$	301

Accretion of Class B Units to redemption value	$	281	$	—
Distributions payable to noncontrolling interest	$	6,870	$	—


The accompanying notes are an integral part of these condensed consolidated financial statements.			14

BKV Corporation

Condensed Consolidated Statements of Stockholders' Equity and Mezzanine Equity
(in thousands)

(Unaudited)

Table of Contents


	Stockholders' Equity												Mezzanine Equity
	Common Stock			Treasury			Additional Paid-In Capital		Retained Earnings		Total Stockholders' Equity		Noncontrolling Interest
	Shares	Amount		Shares	Amount
Balance, December 31, 2024	84,600	$	1,512	214	$	(6,663)	$	1,447,671	$	117,054	$	1,559,574	$	—
Net loss	—	—		—	—		—		(78,666)		(78,666)		—
Common stock issued upon vesting of RSUs, net of shares withheld for income taxes	108	1		—	—		(1,182)		—		(1,181)		—
Equity-based compensation	—	—		—	—		2,067		—		2,067		—
Balance, March 31, 2025	84,708	$	1,513	214	$	(6,663)	$	1,448,556	$	38,388	$	1,481,794	$	—
Net income	—	—			—		—		104,572		104,572		163
Cash contributions from noncontrolling interest	—	—		—	—		—		—		—		4,353
Accretion of Class B Units to redemption value	—	—		—	—		—		(281)		(281)		281
Distribution declared to noncontrolling interest	—	—		—	—		—		—		—		(6,870)
Common stock issued upon vesting of RSUs, net of shares withheld for income taxes	3	—			—		(23)		—		(23)		—
Equity-based compensation	—	—		—	—		4,069		—		4,069		—
Balance, June 30, 2025	84,711	$	1,513	214	$	(6,663)	$	1,452,602	$	142,679	$	1,590,131	$	(2,073)


The accompanying notes are an integral part of these condensed consolidated financial statements.			15

BKV Corporation

Condensed Consolidated Statements of Stockholders' Equity and Mezzanine Equity
(in thousands)

(Unaudited)

Table of Contents


	Stockholders' Equity												Mezzanine Equity
	Common Stock			Treasury			Additional Paid-In Capital		Retained Earnings		Total Stockholders' Equity		Common Stock			Equity-based Compensation		Total Mezzanine Equity
	Shares	Amount		Shares	Amount								Shares	Amount
Balance, December 31, 2023	63,873	$	1,283	213	$	(4,582)	$	1,034,144	$	259,924	$	1,290,769	2,403	$	59,988	$	126,966	$	186,954
Net loss	—	—		—	—		—		(38,585)		(38,585)		—	—		—		—
Adjustment of minority ownership puttable shares to redemption value	—	—		—	—		(1,548)		—		(1,548)		—	1,548		—		1,548
Adjustment of equity-based compensation to redemption value	—	—		—	—		(495)		—		(495)		—	—		495		495
Common stock issued upon vesting of RSUs, net of shares withheld for income taxes	—	—		—	—		—		—		—		69	—		—		—
Equity-based compensation	—	—		—	—		—		—		—		—	—		1,073		1,073
Balance, March 31, 2024	63,873	$	1,283	213	$	(4,582)	$	1,032,101	$	221,339	$	1,250,141	2,472	$	61,536	$	128,534	$	190,070
Net loss	—	—		—	—		—		(59,697)		(59,697)		—	—		—		—
Adjustment of minority ownership puttable shares to redemption value	—	—		—	—		1,060		—		1,060		—	(1,060)		—		(1,060)
Adjustment of equity-based compensation to redemption value	—	—		—	—		194		—		194		—	—		(194)		(194)
Common stock issued upon vesting of RSUs, net of shares withheld for income taxes	—	—		—	—		—		—		—		9	—		—		—
Equity-based compensation	—	—		—	—		—		—		—		—	—		1,072		1,072
Balance, June 30, 2024	63,873	$	1,283	213	$	(4,582)	$	1,033,355	$	161,642	$	1,191,698	2,481	$	60,476	$	129,412	$	189,888


The accompanying notes are an integral part of these condensed consolidated financial statements.			16

Table of Contents

BKV Corporation

Notes to the Condensed Consolidated Financial Statements

(Unaudited)

Note 1 - Business and Basis of Presentation

General

BKV Corporation (“BKV Corp”) was formed on May 1, 2020 and is a corporation registered with the State of Delaware. BKV Corp is a growth driven energy company focused on creating value for its shareholders through organic development of its properties, as well as accretive acquisitions. BKV Corp’s core business is to produce natural gas from its owned and operated upstream businesses.

The majority shareholder of BKV Corp is BNAC. BKV Corp’s ultimate parent company is Banpu Public Company Limited, a public company listed in the Stock Exchange of Thailand. As of August 12, 2025, the date these condensed consolidated financial statements were available to be issued, BNAC owned 75.4% of BKV Corp's shares. The remaining 24.6% of shares of common stock of BKV Corp were owned by non-controlling members of management, members of the board of directors, and employee and non-employee shareholders.

Basis of Presentation of the Unaudited Condensed Consolidated Financial Statements

These condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts for BKV Corp’s wholly-owned subsidiaries and partially-owned subsidiary in which BKV Corp has a controlling interest. The condensed consolidated financial statements are unaudited and should be read in conjunction with the Company’s 2024 Annual Report on Form 10-K, as certain disclosures and information required by GAAP for complete consolidated financial statements have been condensed or omitted. The condensed consolidated financial statements, in the opinion of management, reflect all adjustments, which include normal and recurring adjustments, necessary to fairly state the Company’s financial position, results of operations, and cash flows for the periods presented herein. The interim results are not necessarily indicative of results to be expected for the year ending December 31, 2025 or for any other future annual or interim period. The December 31, 2024 condensed consolidated balance sheet was derived from the Company's 2024 Annual Report on Form 10-K, but does not include all disclosures required by GAAP for annual financial statements.

Together, BKV Corp, its wholly-owned subsidiaries, and its partially-owned subsidiary where BKV Corp has a controlling interest and is the primary beneficiary, are referred to collectively as “BKV” or the “Company.” All intercompany balances and transactions between these entities have been eliminated within the condensed consolidated financial statements. Current and deferred income taxes and related tax expense have been determined based on the stand-alone results of BKV by applying the separate return method to BKV’s operations as if it were a separate taxpayer.

Business Segment Information

In accordance with Accounting Standards Codification (“ASC”) 280 - Segment Reporting, the Company is organized, managed, and identified as one operating segment and one reportable segment as the Company does not distinguish between business lines for the purpose of making decisions about resource allocation and performance management. The Company’s Chief Executive Officer, identified as the Chief Operating Decision Maker (“CODM”), evaluates financial performance on a consolidated basis, primarily using net income from the condensed consolidated statements of operations. Additionally, the CODM reviews reported consolidated revenues, significant segment expenses, and other segment items as presented on the condensed consolidated statements of operations on a monthly basis to allocate resources, manage liquidity, and assess overall Company performance relative to budget. The CODM also monitors total assets and capital expenditures, on a consolidated basis, as presented on the condensed consolidated balance sheets and condensed consolidated statements of cash flows, respectively.

Revision of Previously Issued Financial Statements

In connection with the preparation of the consolidated financial statements for the year ended December 31, 2024, the Company identified an error in its previously issued consolidated financial statements that originated prior to January 1, 2021. Specifically, in connection with the corporate restructuring of BKV Corp in 2020, the tax basis of certain assets was calculated in error resulting in an understatement of deferred tax liabilities, net of $7.4 million, an understatement of tax expense, and an overstatement of retained earnings.


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Management assessed the materiality of this error and concluded it was not material to the Company's previously issued financial statements. Management has revised its previously issued consolidated financial statements to correct the errors as follows (in thousands):


Consolidated Statements of Stockholders’ Equity and Mezzanine Equity	As Previously Reported		Adjusted		As Revised
Retained earnings
Balance, December 31, 2023	$	267,368	$	(7,444)	$	259,924
Balance, March 31, 2024	228,783		(7,444)		221,339
Balance, June 30, 2024	169,086		(7,444)		161,642

Total stockholders' equity
Balance, December 31, 2023	1,298,213		(7,444)		1,290,769
Balance, March 31, 2024	1,257,585		(7,444)		1,250,141
Balance, June 30, 2024	1,199,142		(7,444)		1,191,698

Reclassification

Certain prior period amounts have been reclassified in order to conform to the current period presentation. These reclassifications had no impact on previously reported balance sheets, net income (loss), net cash flows, or stockholders’ equity.

Initial Public Offering

On September 27, 2024, the Company completed its initial public offering (the “IPO”) of 15,000,000 shares of common stock at a price to the public of $18.00 per share. After underwriting discounts and commissions of $16.2 million, the Company received net proceeds from the offering of $253.8 million. The Company also granted the IPO underwriters a 30-day option to purchase up to 2,250,000 additional shares of common stock on the same terms. The underwriters partially exercised the option and on October 28, 2024, purchased 701,003 additional shares of common stock, resulting in additional net proceeds of $11.9 million, after deducting underwriting discounts and commissions of $0.8 million.

Upon consummation of the IPO, 5,026,638 mezzanine shares were converted into common stock.

Liquidity

As of June 30, 2025, the Company held $21.4 million of cash and cash equivalents. The Company’s working capital deficit as of June 30, 2025 was $76.3 million, and for the six months ended June 30, 2025, cash flows provided by operating activities was $98.8 million. The Company intends to make the payments related to its debt and investments in capital expenditures with cash flows from operations. During the six months ended June 30, 2025, the Company purchased put options with several counterparties and paid a premium of $16.2 million. For further discussion on derivative transactions, see Note 5 - Derivative Instruments.

Significant Judgments and Accounting Estimates

The preparation of these condensed consolidated financial statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and the accompanying notes. There have been no significant changes to the Company's accounting estimates from those disclosed in the Company's 2024 Annual Report on Form 10-K.

Significant Accounting Policies

The Company's significant accounting policies are described in the notes to the consolidated financial statements for the year ended December 31, 2024, which are disclosed in the 2024 Annual Report on Form 10-K. There have been no significant changes in accounting policies during the six months ended June 30, 2025.

Common Shares Issued and Outstanding

As of June 30, 2025 and December 31, 2024, the Company had common shares issued and outstanding of 84,711,220 and 84,600,301, respectively.


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Accounting Pronouncements Not Yet Adopted

In November 2024, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2024-03, Disaggregation of Income Statement Expenses. This standard requires that entities (i) disclose amounts of purchases of inventory, employee compensation, and depreciation, depletion, and amortization, including those recognized as part of oil and gas-producing activities (or other amounts of depletion expense) included in each relevant expense caption, (ii) include certain amounts that are already required to be disclosed under current GAAP in the same disclosure as the other disaggregation requirements, (iii) disclose a qualitative description of the amounts remaining in relevant expense captions that are not separately disaggregated quantitatively, and (iv) disclose the total amount of selling expenses and, in annual reporting periods, an entity’s definition of selling expenses. This standard is effective January 1, 2027 with early adoption permitted. Management is currently evaluating the impact this standard will have on the Company’s disclosures.

Recently Adopted Accounting Standards

In November 2023, the FASB issued ASU 2023-07, Improvements to Reportable Segment Disclosures, which requires entities to disclose the title of the chief operating decision maker and, on an interim and annual basis, significant segment expenses and the composition of other segment items for each segment’s reported profit. The standard also permits disclosure of additional measures of segment profit. BKV adopted this guidance effective January 1, 2024 and currently identifies one operating segment and one reportable segment.

In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures, which requires public entities to disclose more consistent and detailed categories in their statutory to effective income tax rate reconciliations and further disaggregate income taxes paid by jurisdiction. For each annual period presented, the new standard requires disclosure of the year-to-date amount of income taxes paid (net of refunds received) disaggregated by federal, state, and foreign. It also requires additional disaggregated information on income taxes paid (net of refunds received) to an individual jurisdiction equal to or greater than 5% of total income taxes paid (net of refunds received). This ASU is effective for the Company prospectively to all annual periods beginning after December 15, 2024, and interim reporting periods beginning after December 15, 2025.

Note 2 - Debt

RBL Credit Agreement

On June 11, 2024, the Company and BKV Upstream Midstream entered into the RBL Credit Agreement with BKV Upstream Midstream as the borrower and BKV Corp as the guarantor on the RBL Credit Agreement. The RBL Credit Agreement includes a maximum credit commitment of $1.5 billion. On May 6, 2025, with the unanimous consent of the credit facility lenders, the Company and BKV Upstream Midstream amended the RBL Credit Agreement to, among other things, increase the borrowing base by $100.0 million and the elected commitment by $65.0 million. This amendment constituted the semiannual borrowing base redetermination. As of June 30, 2025, the RBL Credit Agreement had a borrowing base of $850.0 million, an elected commitment of $665.0 million, and the ability to issue up to $40.0 million in letters of credit. As of June 30, 2025 and December 31, 2024, the Company's RBL Credit Agreement had an outstanding balance of $200.0 million and $165.0 million, respectively. As of August 12, 2025, $282.0 million of revolving borrowings and $14.1 million of letters of credit were outstanding under the RBL Credit Agreement, leaving $368.9 million of available capacity thereunder for future borrowings and letters of credit.

The loans may be borrowed, repaid, and reborrowed during the term of the RBL Credit Agreement. The RBL Credit Agreement matures on June 12, 2028. The obligations under the RBL Credit Agreement are secured and guaranteed on a secured basis by all of BKV Upstream Midstream’s current and future material subsidiaries. Loans under the RBL Credit Agreement bear interest at one, three, or six-month term SOFR or an ABR, as applicable, plus a credit spread adjustment of 0.10% for SOFR borrowings, plus an applicable margin per annum. Interest is payable on the last day of each interest period and at maturity. BKV Upstream Midstream is obligated to pay certain fees to the lenders and administrative agent under the RBL Credit Agreement, including commitment fees on the average daily amount of the undrawn portion of the commitments. During the three and six months ended June 30, 2025, BKV Upstream Midstream recognized $0.5 million and $1.0 million of commitment fees, respectively, which is included in interest expense on the condensed consolidated statements of operations. During the three and six months ended June 30, 2024, BKV Upstream Midstream did not recognize any commitment fees.

The RBL Credit Agreement contains various restrictive covenants that, among other things, limit BKV Upstream Midstream's ability and the ability of its restricted subsidiaries to, subject to certain exceptions: (i) incur indebtedness; (ii) incur liens; (iii) acquire or merge with any other company; (iv) sell assets or equity interests of its subsidiaries; (v) make investments; (vi) pay dividends or make other restricted payments; (vii) change its lines of business; (viii) enter into certain hedge agreements;


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(ix) enter into transactions with affiliates; (x) own any subsidiary that is not organized in the United States; (xi) prepay any unsecured senior or subordinated indebtedness; (xii) engage in certain marketing activities; and (xiii) allow, on a net basis, gas imbalances, take-or-pay, or other prepayments with respect to proved oil and gas properties.

Beginning with the fiscal quarter ending September 30, 2024, the RBL Credit Agreement requires BKV Upstream Midstream to always hedge not less than 50% of projected production from our proved developed producing reserves for the subsequent 24 calendar month period immediately following such required delivery date.

The RBL Credit Agreement also includes financial covenants that require BKV Upstream Midstream to maintain:

• on a quarterly basis, a minimum Current Ratio (as defined in the RBL Credit Agreement) of no less than 1.00 to 1.00; and

• on a quarterly basis, a Net Leverage Ratio (as defined in the RBL Credit Agreement) of no greater than 3.25 to 1.00.

The RBL Credit Agreement includes customary equity cure rights that will enable BKV Upstream Midstream to cure certain breaches of the minimum current ratio covenant or the maximum net leverage ratio covenant. As of June 30, 2025, BKV Upstream Midstream was in compliance with such covenants in the RBL Credit Agreement.

The RBL Credit Agreement generally includes customary events of default for a reserve-based credit facility, some of which allow for an opportunity to cure. If an event of default relating to bankruptcy or other insolvency events occurs, the revolving loans will immediately become due and payable; if any other event of default exists, the administrative agent or the requisite lenders will be permitted to accelerate the maturity of the revolving loans. The RBL Credit Agreement is secured by substantially all of BKV Upstream Midstream's assets and those of the guarantors, and upon an event of default the agent under the RBL Credit Agreement could commence foreclosure proceedings.

Financing costs related to the RBL Credit Agreement are deferred and capitalized as debt issuance costs and are included within other assets on the condensed consolidated balance sheets. As of June 30, 2025 and December 31, 2024, $6.6 million and $6.9 million, respectively, of unamortized debt issuance costs remained outstanding. As of June 30, 2025 and December 31, 2024, the effective interest rate on the RBL Credit Agreement was 7.41% and 7.50%, respectively, and the outstanding letters of credit were $14.1 million for both periods.

Subordinated Intercompany Loan Agreement

On June 18, 2024, the Company paid down $25.0 million of the $75.0 million outstanding on the related party loan with BNAC, including interest, and on September 30, 2024, the Company repaid the outstanding balance of $50.0 million, including interest, with proceeds from the IPO.

Note 3 - Natural Gas Properties & Other Property and Equipment

As of June 30, 2025 and December 31, 2024, accumulated depreciation, depletion, and amortization for developed natural gas properties was $759.5 million and $697.0 million, respectively. Depreciation, depletion, and amortization expense for developed natural gas properties was $30.7 million and $53.0 million for the three months ended June 30, 2025 and 2024, respectively, and $62.5 million and $98.1 million for the six months ended June 30, 2025 and 2024, respectively.

As of June 30, 2025 and December 31, 2024, accumulated depreciation for midstream assets was $20.5 million and $17.3 million, respectively. Depreciation expense on midstream assets was $1.6 million and $1.8 million for the three months ended June 30, 2025 and 2024, respectively, and $3.2 million and $3.7 million for the six months ended June 30, 2025 and 2024, respectively.


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Other property and equipment consisted of the following:


(in thousands)	June 30, 2025		December 31, 2024
Carbon capture, utilization, and sequestration	$	80,064	$	69,743
Buildings	6,746		15,707
Furniture, fixtures, equipment, and vehicles	20,280		19,306
Computer software	6,028		5,595
Leasehold improvements	1,685		1,685
Land	3,090		3,090
Construction in process	9,347		3,575
Total	127,240		118,701
Accumulated depreciation	(22,987)		(21,401)
Other property and equipment, net	$	104,253	$	97,300

Depreciation expense for other property and equipment was $1.6 million and $1.5 million for the three months ended June 30, 2025 and 2024, respectively, and $3.3 million and $3.0 million for the six months ended June 30, 2025 and 2024, respectively. During the three months ended June 30, 2025 and 2024, the Company received proceeds on the sale of other properties of $0.2 million and $0.9 million, respectively, and recognized a gain on sale of these properties of $0.1 million and $0.7 million, respectively, which is included in other revenues in the condensed consolidated statements of operations. During the six months ended June 30, 2025 and 2024, the Company received proceeds on the sale of other properties of $1.3 million and $1.6 million, respectfully, and recognized a gain on sale of these properties of $1.2 million and $0.8 million, respectively, which is included in the other revenues in the condensed consolidated statements of operations.

Sales of BKV Chaffee Corners, LLC and BKV Chelsea, LLC

On June 14, 2024, the Company sold its wholly owned subsidiary, Chaffee, representing a non-operated interest in approximately 9,800 net acres and 116.0 gross (24.2 net) wells and 122 Bcfe of proved reserves in NEPA, as well as the Company's interest in the Repsol Oil and Gas operated midstream system, for $106.7 million. For the three and six months ended June 30, 2024, the Company recognized a gain on the sale of Chaffee of $6.0 million, net of transaction costs of $3.5 million, which is included in the gain on sale of business in the condensed consolidated statements of operations. The Company recognized additional proceeds of $1.1 million upon final settlement on December 6, 2024.

On June 28, 2024, Chelsea sold certain of its non-operated upstream assets, including interest in approximately 6,800 net acres and 214.0 gross (15.4 net) wells and 35 Bcfe of proved reserves in NEPA, for a purchase price of $25.0 million, subject to adjustment, and transaction costs of approximately $0.5 million. The purchase price was reduced by $0.2 million upon final settlement on November 18, 2024. Due to the immateriality of the upstream assets sold, the Company utilized the practical expedient to account for the sale of Chelsea's non-operated upstream assets sold as a normal retirement with no gain or loss recognized as sale of these assets did not significantly impact the depletion rate with respect to the total reserves retained in NEPA.

As of June 30, 2025, the Company held approximately 19,097 net acres in NEPA, 97% of which was held by production.

Asset Held for Sale

The Company classifies assets as “held for sale” when, among other factors, management approves and commits to sell the assets with the intent to complete the sale within one year. The net assets held for sale are then recorded at the lower of the current value and the fair market value, less costs to sell, if any.

As of June 30, 2025, the Company approved the plan to sell its field office in Bridgeport, Texas. The Company has classified this asset as held for sale, which is presented separately on the condensed consolidated balance sheets. The Company recognized an impairment on the field office of $2.4 million using an estimated selling price of $5.5 million. The impairment is netted within other revenues on the condensed consolidated statements of operations. On July 21, 2025, the Company sold the Bridgeport field office for $5.5 million, and recognized fees associated with this sale of $0.4 million.

See below for the major class of assets held for the sale for the Bridgeport field office:


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(in thousands)	June 30, 2025
Buildings	$	6,515
Accumulated depreciation	(1,015)
Total asset held for sale	$	5,500

Note 4 - Fair Value Measurements

As the Company uses the market approach to determine the fair value of its derivative instruments, these fair values are also compared to the values given by counterparties for reasonableness. Since natural gas and NGL swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. The Company factors its own non-performance risk into the valuation of derivatives using current published credit default swap rates. As of June 30, 2025 and December 31, 2024, the impact of the non-performance risk adjustment to the Company's fair value of commodity derivative liabilities was $5.7 million and $6.6 million, respectively.

The following tables set forth by level within the fair value hierarchy, the financial assets and liabilities that were accounted for at fair value on a recurring basis:


	June 30, 2025
	Fair Value Measurements Using:
(in thousands)	Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Financial assets
Derivative instruments	$	7,178	$	—	$	7,178
Financial liabilities
Derivative instruments	89,656		—		89,656


	December 31, 2024
	Fair Value Measurements Using:
(in thousands)	Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total


Financial liabilities
Derivative instruments	$	67,634	$	—	$	67,634

The contingent consideration was generated from the Devon Barnett Acquisition. As of December 31, 2024, the contingent consideration was included in current liabilities in the condensed consolidated balance sheets as a payable as the final payout of $20.0 million was made on January 8, 2025. The Devon Barnett Acquisition and the Exxon Barnett Acquisition contingencies are described further in Note 11 - Commitments and Contingencies. The Devon Barnett Acquisition was accounted for as an asset acquisition with the contingent consideration meeting the criteria of a derivative in accordance with ASC 815 - Derivatives and Hedging. See Note 5 - Derivative Instruments for further discussion.

The minority ownership puttable shares from the 2021 Plan (as defined in Note 8 - Stockholders' Equity) were recorded at fair value upon initial recognition in mezzanine equity, and its common stock was valued using both observable (Level 2) and unobservable (Level 3) inputs. Subsequent to the Company's IPO, the minority ownership puttable shares were converted to common stock. The minority ownership puttable shares are further described in Note 8 - Stockholders' Equity.

Equity-based compensation from the 2021 Plan was recorded at fair market value on the grant date. The underlying market condition was valued using the application of Monte Carlo simulations using both observable (Level 2) and unobservable (Level 3) inputs. Prior to the Company's IPO, the remaining components of the awards were valued based on the fair market value of the


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common stock of the Company, determined using the same valuation methodologies applied to the minority ownership puttable shares. Equity-based compensation is further described in Note 8 - Stockholders' Equity.

The table below sets forth the changes in the Company's Level 3 fair value measurements for the six months ended June 30, 2024:






(in thousands)	Contingent Consideration		Minority Ownership		Equity-Based Compensation		Total
Balance, December 31, 2023	$	29,676	$	59,988	$	126,966	$	216,630
Grant date fair value of equity-based compensation, pre-IPO	—		—		1,073		1,073
Change in fair market value	(6,594)		1,548		495		(4,551)
Balance, March 31, 2024	23,082		61,536		128,534		213,152
Grant date fair value of equity-based compensation, pre-IPO	—		—		1,072		1,072
Change in fair market value	524		(1,060)		(194)		(730)
Balance, June 30, 2024	$	23,606	$	60,476	$	129,412	$	213,494

Note 5 - Derivative Instruments

The Company may utilize derivative contracts in connection with its natural gas and NGL operations to provide an economic hedge of the Company’s exposure to commodity price risk associated with anticipated future natural gas and NGL production. The Company also determined that the contingent consideration generated from the Devon Barnett Acquisition met the definition of a derivative in accordance with ASC 815 - Derivatives and Hedging, and the fair value of the contingent consideration was $20.0 million as of December 31, 2024, and is included in contingent consideration payable in the condensed consolidated balance sheets. The change in the fair value of this contingent consideration was a loss of $0.7 million and a gain of $3.9 million for the three and six months ended June 30, 2024, respectively, and is included in gains (losses) on contingent consideration liabilities on the condensed consolidated statements of operations. See Note 11 - Commitments and Contingencies for further discussion.

The derivative contracts outstanding as of June 30, 2025 consisted of commodity swaps, basis swaps, put and call options, and producer collar agreements, subject to master netting agreements with each individual counterparty. The following table presents gross commodity derivative balances prior to applying netting adjustments recorded in the condensed consolidated balance sheets:


		June 30, 2025
(in thousands)	Balance Sheet Location	Gross Amounts of Assets and Liabilities		Offset Adjustments		Net Amounts of Assets and Liabilities
Current derivative assets	Commodity derivative assets, current	$	10,182	$	(9,626)	$	556
Noncurrent derivative assets	Commodity derivative assets	14,843		(8,221)		6,622
Current derivative liabilities	Commodity derivative liabilities, current	53,637		(9,626)		44,011
Noncurrent derivative liabilities	Commodity derivative liabilities	53,866		(8,221)		45,645


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		December 31, 2024
(in thousands)	Balance Sheet Location	Gross Amounts of Assets and Liabilities		Offset Adjustments		Net Amounts of Assets and Liabilities
Current derivative assets	Commodity derivative assets, current	$	5,187	$	(5,187)	$	—
Noncurrent derivative assets	Commodity derivative assets	872		(872)		—
Current derivative liabilities	Commodity derivative liabilities, current	25,464		(5,187)		20,277
Noncurrent derivative liabilities	Commodity derivative liabilities	48,229		(872)		47,357

Collar, Commodity Swap, and Basis Swap Contracts

A commodity collar provides for a price floor and a price ceiling. The floating price for the collar contract is traded for a fixed price when the floating price is not between the floor and ceiling. If the floating price is between these contracted prices, no trade occurs. A commodity swap agreement is an agreement whereby a floating price based on the underlying commodity is traded for a fixed price over a specified period. Basis swaps provide a guaranteed price differential for natural gas from two different specified delivery points over a specified period. The fair value of open collar, commodity swap, and basis swap contracts reported in the condensed consolidated balance sheets may differ from that which would be realized in the event the Company terminated its position in the respective contract.

Derivative Contracts

The following tables set forth the derivative gains (losses), net on the condensed consolidated statements of operations:


	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands)	2025		2024		2025		2024
Gain (loss) on settled derivatives, net	$	9,273	$	31,471	$	(8,933)	$	67,935
Gain (loss) on unsettled derivatives, net	102,935		(38,957)		(31,050)		(79,100)
Derivative gains (losses), net	$	112,208	$	(7,486)	$	(39,983)	$	(11,165)

Settled derivative gains, net for the six months ended June 30, 2024 includes gains of $13.3 million related to the termination of certain natural gas commodity derivative swap contracts prior to their contractual settlement dates. $8.4 million of such gains is attributable to early-terminated natural gas commodity derivative swap contracts covering production during the six months ended June 30, 2024. There were no early-terminated natural gas commodity swap contracts during the three months ended June 30, 2024 or during the three and six months ended June 30, 2025.

During the first quarter in 2024, the Company entered into an agreement to sell a call option and subsequently received a net premium of $23.5 million for contracts that settle in 2026 and 2027. The call option has an established ceiling price of $5.00 per MMBtu. If at the time of settlement the contracted settlement price exceeds the ceiling price, the Company pays the counterparty an amount equal to the difference between the contracted settlement price and the ceiling price multiplied by the contract volumes. The premium received was recorded as a liability and is subsequently adjusted to the current fair value of the option written.

During the first quarter in 2025, the Company entered into agreements to buy put options and subsequently paid a net premium of $16.2 million for contracts that settle in 2026 and 2027. The put options have an established floor of $3.00 per MMBtu. If at the time of settlement the contracted settlement price falls below the floor, the counterparties pay the Company an amount equal to the difference between the contracted settlement price and the floor multiplied by the contract volumes. The premium paid was recorded as an asset and is subsequently adjusted to the current fair value of the option written.

Volume of Derivative Activities

As of June 30, 2025, the Company’s derivative activities based on volume and contract prices, categorized by primary underlying risk and related commodity, by year, were as follows:


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The following table represents natural gas commodity derivatives indexed to NYMEX Henry Hub pricing:


Instrument	MMBtu	Weighted Average Price (USD)		Weighted Average Price Floor		Weighted Average Price Ceiling		Fair Value as of June 30, 2025 (in thousands)
2025
Swap	48,960,000	$	3.41					$	(19,183)
Collars	6,120,000			$	3.71	$	4.11	$	294
2026
Swap	71,575,000	$	3.71					$	(36,849)
Collars	28,300,000			$	3.70	$	4.22	$	(7,319)
Call options	36,500,000					$	5.00	$	(15,598)
Put options	36,500,000			$	3.00			$	5,815
2027
Swap	36,500,000	$	3.96					$	(306)
Collars	36,500,000			$	3.57	$	3.98	$	(6,025)
Call options	36,500,000					$	5.00	$	(15,686)
Put options	36,500,000			$	3.00			$	10,135

The following table represents natural gas basis derivatives based on the applicable basis reference price listed below:


Instrument	Basis Reference Price	MMBtu	Weighted Average Basis Differential		Fair Value as of June 30, 2025 (in thousands)
2025
Swap	Transco Leidy Basis	6,440,000	$	(0.86)	$	1,892
Swap	HSC Basis	14,720,000	$	(0.45)	$	(330)
Swap	Transco St 85 (Z4) Basis	11,960,000	$	0.45	$	(72)

The following table represents natural gas liquids commodity derivatives for contracts, by contract type, expiring through December 31, 2027 based on the applicable index listed below:


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Instrument	Commodity Reference Price	Gallons	Weighted Average Price (USD)		Fair Value as of June 30, 2025 (in thousands)
2025
Swap	OPIS Purity Ethane Mont Belvieu	54,096,000	$	0.25	$	651
Swap	OPIS IsoButane Mont Belvieu Non-TET	3,864,000	$	0.87	$	(224)
Swap	OPIS Normal Butane Mont Belvieu Non-TET	4,830,000	$	0.83	$	(185)
Swap	OPIS Propane Mont Belvieu Non-TET	21,252,000	$	0.73	$	(239)
Swap	OPIS Natural Gasoline Mont Belvieu Non-TET	7,728,000	$	1.41	$	1,113
2026
Swap	OPIS Purity Ethane Mont Belvieu	94,762,500	$	0.25	$	(2,141)
Swap	OPIS IsoButane Mont Belvieu Non-TET	6,221,250	$	0.86	$	(44)
Swap	OPIS Normal Butane Mont Belvieu Non-TET	10,053,750	$	0.82	$	17
Swap	OPIS Propane Mont Belvieu Non-TET	37,327,500	$	0.70	$	(564)
Swap	OPIS Natural Gasoline Mont Belvieu Non-TET	16,275,000	$	1.40	$	2,455
2027
Swap	OPIS Purity Ethane Mont Belvieu	45,990,000	$	0.28	$	(85)

Note 6 - Revenue from Contracts with Customers

All of the Company's revenues from contracts with customers are generated in the states of Pennsylvania and Texas. Revenues consist of the following:


	Three Months Ended June 30, 2025
(in thousands)	Pennsylvania		Texas		Total
Natural gas	$	15,035	$	140,527	$	155,562
NGLs	—		41,630		41,630
Oil	—		2,537		2,537
Total natural gas, NGL, and oil sales	15,035		184,694		199,729

Marketing revenues	—		1,372		1,372
Midstream revenues	—		2,739		2,739

Related party and other(1)	—		3,304		3,304
Total	$	15,035	$	192,109	$	207,144


	Three Months Ended June 30, 2024
(in thousands)	Pennsylvania		Texas		Total
Natural gas	$	5,453	$	77,387	$	82,840
NGLs	—		41,216		41,216
Oil	—		1,798		1,798
Total natural gas, NGL, and oil sales	5,453		120,401		125,854

Marketing revenues	—		2,046		2,046
Midstream revenues	771		2,607		3,378

Related party and other(1)	—		2,678		2,678
Total	$	6,224	$	127,732	$	133,956


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	Six Months Ended June 30, 2025
(in thousands)	Pennsylvania		Texas		Total
Natural gas	$	39,607	$	283,938	$	323,545
NGLs	—		86,313		86,313
Oil	—		5,997		5,997
Total natural gas, NGL, and oil sales	39,607		376,248		415,855

Marketing revenues	—		7,857		7,857
Midstream revenues	—		5,510		5,510

Related party and other(1)	—		6,982		6,982
Total	$	39,607	$	396,597	$	436,204


	Six Months Ended June 30, 2024
(in thousands)	Pennsylvania		Texas		Total
Natural gas	$	17,945	$	161,230	$	179,175
NGLs	—		84,632		84,632
Oil	—		3,734		3,734
Total natural gas, NGL, and oil sales	17,945		249,596		267,541

Marketing revenues	—		6,967		6,967
Midstream revenues	2,014		5,492		7,506

Related party and other(1)	—		4,506		4,506
Total	$	19,959	$	266,561	$	286,520

____________________________________________________

(1)Excludes gains (losses) on sales of assets included in other revenue on the condensed consolidated statements of operations.

Accounts Receivable and Revenue from Contracts with Customers

Substantially all of the Company’s accounts receivable result from the sale of natural gas and joint interest billings. The Company sells natural gas, NGLs, and oil to fewer than five customers and bills working interest owners for costs related to development of the Company’s natural gas properties. As of June 30, 2025 and December 31, 2024, the Company’s receivables from contracts with customers were $29.6 million and $45.8 million, respectively. Also, as of June 30, 2025 and December 31, 2024, one purchaser accounted for more than 10% of accounts receivables, and for the three months ended June 30, 2025 and 2024, that purchaser’s revenues were $152.1 million and $71.8 million, respectively, and for the six months ended June 30, 2025 and 2024, the same purchaser’s revenues were $319.5 million and $168.2 million, respectively. Another purchaser’s revenues, that also accounted for more than 10% of the Company’s revenues during the three months ended June 30, 2025 and 2024 amounted to $38.4 million and $34.4 million, respectively, and during the six months ended June 30, 2025 and 2024, amounted to $79.1 million and $72.2 million, respectively. The Company does not believe that the loss of these customers would have a material adverse effect on the condensed consolidated financial statements because alternative customers are readily available.

Note 7 - Accounts Payable and Accrued Liabilities


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Accounts payable and accrued liabilities included in current liabilities consist of the following:


(in thousands)	June 30, 2025		December 31, 2024
Accounts payable	$	76,005	$	53,238
Revenues payable	16,241		17,921

Accrued payroll	13,866		23,435
Oil and gas production and other taxes payable	13,482		21,263
Other accrued liabilities	4,208		5,509
Total	$	123,802	$	121,366

Note 8 - Stockholders' Equity

Equity-Based Compensation

2024 Equity and Incentive Compensation Plan

The Company's 2024 Equity and Incentive Compensation Plan (the “2024 Plan”) became effective immediately prior to the consummation of the IPO. The 2024 Plan permits the grant of awards to the non-employee directors, officers, and other employees of BKV Corp and its controlled subsidiaries in order to provide incentives and rewards for service and/or performance. The Company may grant stock options, appreciation rights, restricted stock, restricted stock units (“RSUs”), performance shares, performance units, cash incentive awards, and certain other awards based on or related to shares of the Company's common stock. Under the 2024 Plan, the Company can issue up to 5,000,000 shares of its common stock, which are subject to adjustment to reflect any extraordinary cash dividend, stock dividend, split, or combination of the Company's common stock. The aggregate number of shares of the Company's common stock available for award under the 2024 Plan will be reduced by one share of the Company's common stock for every one share of its common stock subject to an award granted under the 2024 Plan. Each grant of an award under the 2024 Plan will be evidenced by an award agreement that includes terms and provisions, determined by the Company's Compensation Committee (or other committee of the board of directors designated by the board to administer the 2024 Plan), which outlines the number of shares of common stock, earning or vesting terms, and any other terms consistent with the 2024 Plan.

Any shares of common stock awarded under the 2024 Plan that have been canceled, forfeited, expired, settled for cash shares, or is unearned (in whole or part) will be added back to the aggregate number of shares of common stock available under the 2024 Plan, with the exception of the following: (i) shares of common stock withheld by the Company in payment of the exercise price of a stock option; (ii) shares of common stock tendered or otherwise used in payment of the exercise price of a stock option; (iii) shares of common stock withheld by the Company or tendered or otherwise used to satisfy a tax withholding obligation; (iv) shares of common stock subject to share-settled appreciation rights that are not actually issued in connection with the settlement of such appreciation right; and (v) shares of common stock reacquired by the Company on the open market or otherwise using cash proceeds from the exercise of stock options. As of June 30, 2025, 2,773,009 shares were available for future grants under the 2024 Plan.

Performance-Based Restricted Stock Units

On September 27, 2024, the Company granted 704,649 performance-based restricted stock units (“PRSUs”) under the 2024 Plan that cliff vest on December 31, 2026 and are subject to a performance period beginning January 1, 2024 and ending on December 31, 2026. During the three and six months ended June 30, 2025, the Company granted 46,263 and 617,734, respectively, PRSUs, which cliff vest on December 31, 2027 and are subject to a performance period beginning January 1, 2025 and ending on December 31, 2027 (collectively with the grants issued in 2024, the “PRSU Performance Period”). The table below


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summarizes the PRSU activity for the six months ended June 30, 2025:






(in thousands, except per share amounts)	Shares	Weighted Average Grant Date Fair Value
Unvested PRSUs as of January 1, 2025	703	$	12.23
Granted	618	$	19.00
Vested	(32)	$	6.75
Forfeited	(71)	$	7.31
Unvested PRSUs as of June 30, 2025	1,218	$	15.61

These PRSUs are eligible to be earned based on three performance conditions: (i) annualized Total Shareholder Return (“aTSR”) of the Company's common stock during the PRSU Performance Period, weighted at 30%, (ii) relative Total Shareholder Return (“rTSR”) of the common stock of the Company's benchmark group during the PRSU Performance Period, weighted at 30%, and (iii) Return on Capital Employed (“ROCE”) based on the average annual performance over the PRSU Performance Period, weighted at 40%.

The aTSR and rTSR components of the awards are market-based conditions valued using the Monte-Carlo Simulation pricing model, which calculates multiple potential outcomes and establishes grant date fair value based on the most likely outcome. For purposes of the grant date fair value during the six months ended June 30, 2025, the aTSR and rTSR components assumed a risk free rate of 4.0%, a dividend yield of an immaterial amount, and volatility of 40% that used a combination of daily historical and implied volatility over a look back period commensurate with the remaining term of the assets. The weighted average grant date fair value of the aTSR and rTSR components of PRSU awards granted during the three months ended June 30, 2025 was $19.10 and $31.46, respectively, and for the six months ended June 30, 2025 they were $14.03 and $23.12, respectively.

ROCE is considered to be a non-market performance condition. Thus, the likelihood of achievement must be reassessed at every reporting period, and compensation expense is adjusted accordingly. As of June 30, 2025, management estimates ROCE performance for the post IPO grants to be higher than the target performance by approximately 22.3%, and for the grants that were issued during the six months ended June 30, 2025 to be higher than the target performance level by approximately 82.5%. The grant date fair value of the PRSUs presented in the activity for the three and six months ended June 30, 2025 takes into account the grant date fair value for ROCE, due to the non-market performance conditions being probable of achievement as of the respective modification date or grant date which establishes a grant date fair value. The weighted average grant date fair value of the ROCE component of PRSU awards granted during the three and six months ended June 30, 2025 was $22.63 and $19.64, respectively.

As of June 30, 2025, there was $19.4 million of unrecognized compensation expense related to the PRSU awards, which will be amortized over a weighted average period of 2.0 years.

Equity-based compensation related to PRSUs was $2.9 million and $4.1 million for the three and six months ended June 30, 2025, respectively, which is included in general administrative expenses in the condensed consolidated statements of operations.

Time-Based Restricted Stock Units

During the three and six months ended June 30, 2025, the Company granted 53,886 and 434,773, respectively, time-based restricted stock units (“TRSUs”) under the 2024 Plan. Under the applicable provisions of the 2024 Plan, the TRSU incentive award vests annually over three anniversary dates in equal portions with the first tranche vesting on January 1, 2025, subject to continued employment with the Company and board of director approval. The table below summarizes the TRSU activity for the


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six months ended June 30, 2025:






(in thousands, except per share amounts)	Shares	Weighted Average Grant Date Fair Value
Unvested TRSUs as of January 1, 2025	469	$	18.05
Granted	435	$	19.89
Vested	(156)	$	18.05
Forfeited	(49)	$	18.24
Unvested TRSUs as of June 30, 2025	699	$	19.18

As of June 30, 2025, there was $11.4 million of unrecognized compensation expense related to the 2024 TRSU awards, which will be amortized over a weighted average period of 2.2 years.

Equity-based compensation related to the TRSUs was $1.2 million and $2.1 million for the three and six months ended June 30, 2025, respectively, which is included in general administrative expenses in the condensed consolidated statements of operations.

Employee Stock Purchase Plan

The Company's Employee Stock Purchase Plan (the “ESPP”) became effective immediately prior to the consummation of the IPO. A total of 500,000 shares of the Company's common stock are available for awards under the ESPP and only permits eligible employees to purchase shares of the Company's common stock through payroll deductions, which cannot exceed 10% of the employee's eligible compensation. The ESPP will be implemented through a series of offerings of up to a period of 27 months, which will consist of one offering period. During the offering period, payroll contributions will accumulate without interest and, on the last trading day of the offering period, accumulated payroll deductions will be used to purchase shares of the Company's common stock. For the three and six months ended June 30, 2025, the Company did not recognize any equity-based compensation expense related to the ESPP.

2021 Equity and Incentive Compensation Plan

On January 1, 2021, the BKV Corporation Long-Term Incentive Plan (the “2021 Plan”) was established. Upon consummation of the IPO, 7,724,499 RSUs were considered to have been granted under ASC 718 - Compensation-Stock Compensation (“ASC 718”), when taking into consideration performance RSUs at the maximum performance level and TRSUs anticipated to be legally granted in the three years following inception. As of December 31, 2024, the awards considered granted under ASC 718 since inception equaled the number of RSUs legally granted. Prior to the Company's IPO, RSUs under the 2021 Plan were recognized in mezzanine equity on the condensed consolidated statements of stockholders' equity and mezzanine equity and were valued using unobservable inputs. See Note 4 - Fair Value Measurements for further detail.

Performance-Based Restricted Stock Units

PRSUs cliff vest and were subject to a vesting or performance period beginning January 1, 2021 and ending on December 31, 2023 (the “Performance Period”). As of December 31, 2023, or the Performance Period, the Company achieved its goals as follows: TSR met its threshold at 136%, ROCE met its threshold at 131%, and IPO readiness met its threshold at 200%. In February 2024, the Plan’s committee approved the Company’s goals and the PRSUs outstanding as of December 31, 2023 vested with some being forfeited prior to the Plan’s approval.

The following table summarizes the PRSU activity under the 2021 Plan for the six months ended June 30, 2024:


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(in thousands, except per share amounts)	Shares	Weighted Average Grant Date Fair Value
Unvested PRSUs as of December 31, 2023	3,967	$	19.02
Vested	(3,963)	$	19.02
Forfeited	(4)	$	19.02
Unvested PRSUs as of June 30, 2024	—	$	—

Time-Based Restricted Stock Units

The following table summarizes the TRSU activity under the 2021 Plan for the six months ended June 30, 2024:






(in thousands, except per share amounts)	Shares	Weighted Average Grant Date Fair Value
Unvested TRSUs as of December 31, 2023	727	$	22.37

Vested (1)	(277)	$	22.12
Forfeited	(20)	$	22.12
Unvested TRSUs as of June 30, 2024	430	$	22.37

__________________________________________________

(1) For the six months ended June 30, 2024, the total fair value of the shares vested was $28.48.

For the three and six months ended June 30, 2024, equity-based compensation expense related to the TRSUs under the 2021 Plan was $1.0 million and $2.1 million, respectively, which is included in general and administrative expenses in the condensed consolidated statements of operations. Upon consummation of the IPO, the remaining TRSUs from the 2021 Plan vested.

Note 9 - Equity Method Investment

The Company is a 50% owner of BKV-BPP Power, which is accounted for as an equity method investment. BKV-BPP Power owns and operates the Temple Plants, which are two combined cycle gas turbine and steam turbine power plants located on the same site in the ERCOT North Zone in Temple, Texas. The Temple Plants deliver power to customers on the ERCOT power network in Texas. BKV-BPP Power also has a wholly-owned subsidiary that engages in retail power sales to customers in Texas.

BKV-BPP Power has a term loan from each of its affiliates, BNAC and BPPUS, each in the amount of $141.0 million, both of which mature on November 1, 2026.

On May 30, 2025, the Company entered into a credit facility agreement with BKV-BPP Power to allow BKV-BPP Power to borrow up to $10.0 million from the Company (“BKV-BPP Power Credit Facility”). Interest on the outstanding principal is at six-month SOFR plus an interest rate margin of 5.35%, and payable on a semi-annual basis and upon expiration of the term of the facility. The term of the BKV-BPP Power Credit Facility is from June 1, 2025 until the earlier of May 31, 2027 or until BKV-BPP Power secures a working capital facility from other financial sources. As of June 30, 2025, there were no outstanding borrowings on the BKV-BPP Power Credit Facility.

The Company has an Administrative Service Agreement (“ASA”) with BKV-BPP Power, in which the Company provides certain services as required by the ASA, on an annual basis with options to extend. During the three months ended June 30, 2025 and 2024, the Company recognized revenues of $0.4 million and $1.1 million, respectively, and for the six months ended June 30, 2025 and 2024, recognized revenues of $0.9 million and $2.2 million, respectively, related to the services provided under the ASA, which is included in related party revenues on the condensed consolidated statements of operations.

During the three months ended June 30, 2025 and 2024, the Company recognized, based on its 50% ownership interest in BKV-BPP Power, earnings of $9.1 million and losses of $15.3 million, respectively, and during the six months ended June 30, 2025 and 2024, the Company recognized losses of $0.5 million and $23.0 million, respectively. For the three months ended June 30, 2025 and 2024, BKV-BPP Power's total revenues, net, included unrealized derivative gains of $11.5 million and unrealized derivative losses of $25.3 million, respectively, and operating expenses included unrealized derivative losses of $3.3 million and


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$3.7 million, respectively. For the six months ended June 30, 2025 and 2024, BKV-BPP Power's total revenues, net, included unrealized derivative losses of $4.5 million and $31.1 million, respectively, and operating expenses included unrealized derivative losses of $0.3 million and $5.7 million, respectively.

The table below sets forth the summarized financial information of BKV-BPP Power:


Income Statement	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
(in thousands)	(unaudited)				(unaudited)
Total revenues, net	$	136,742	$	86,801	$	234,414	$	171,771
Depreciation and amortization	9,536		9,067		19,163		18,952
Operating expenses	94,561		90,315		188,695		163,632
Income (loss) from operations	32,645		(12,581)		26,556		(10,813)
Interest expense	(15,949)		(18,768)		(32,022)		(36,949)
Other income	1,480		843		4,472		1,842
Net income (loss)	$	18,176	$	(30,506)	$	(994)	$	(45,920)

Note 10 - Investment in the BKV-CIP Joint Venture

On May 8, 2025, BKV dCarbon Ventures, together with C Squared Solutions, Inc. (the “Class B Member”), a subsidiary of the Energy Transition Fund managed by Copenhagen Infrastructure Partners (CIP), and for the limited purposes specified therein, BKV Corporation, entered into the BKV-CIP JV Agreement forming BKV dCarbon Project, LLC (the “BKV-CIP Joint Venture”) for the purpose of developing CCUS projects. On May 8, 2025, BKV dCarbon Ventures contributed to the BKV-CIP Joint Venture $40.3 million of CCUS assets that included the BKV dCarbon Barnett Zero, LLC and BKV dCarbon Las Tiendas, LLC and related assets (including the Barnett Zero and Eagle Ford CCUS projects) at book value, $4.1 million of Section 45Q accrued receivables, and committed to future contributions of certain CCUS projects, related assets, and/or cash in exchange for an interest in the BKV-CIP Joint Venture and 4,796,421 Class A Units at $10.00 per share. The Class B Member committed up to an initial $500.0 million in cash for use by the BKV-CIP Joint Venture in construction and operating new CCUS projects across the United States in exchange for no more than a 49% interest in the BKV-CIP Joint Venture and 49% of the Section 45Q tax credits generated in 2024 through the date of the BKV-CIP JV Agreement. As of June 30, 2025, the Class B Member contributed $4.4 million and was obligated to contribute an additional $5.2 million, which was contributed on July 31, 2025. In exchange for the Class B Member's contribution to the BKV-CIP Joint Venture as of June 30, 2025 and following the additional contribution on July 31, 2025, the Class B Member has received a total of 435,250 and 518,523, respectively, of the BKV-CIP Joint Venture's Class B Units at $10.00 per share. The subscription receivable as of June 30, 2025 of $5.2 million is netted within noncontrolling interest and mezzanine equity on the condensed consolidated balance sheets.

Net income (loss) is allocated to each member pursuant to the BKV-CIP JV Agreement's liquidation provisions. For the three and six months ended June 30, 2025, BKV dCarbon Ventures and the Class B Member's allocation in BKV-CIP Joint Venture's net income (loss) was 58% and 42%, respectively.

Variable Interest Entity

The Company considers the BKV-CIP Joint Venture a variable interest entity (“VIE”) in accordance with ASC 810, Consolidation as the Company is deemed to be the primary beneficiary of the BKV-CIP Joint Venture. Generally, a VIE is an entity with at least one of the following conditions: (i) the total equity investment at risk is insufficient to allow the entity to finance its activities without additional subordinated financial support, or (ii) the holders of the equity investment at risk, as a group, lack the characteristics of having a controlling financial interest. The primary beneficiary of a VIE is an entity that has a variable interest or a combination of variable interests that provide such entity with a controlling financial interest in the VIE. An entity is deemed to have a controlling financial interest in a VIE if it has both of the following characteristics: (i) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance, and (ii) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.


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The BKV-CIP Joint Venture is exposed to similar operational risks as the Company, and is therefore monitored and evaluated on a similar basis by management. The carrying amounts and classification of the consolidated VIE assets and liabilities included in the consolidated balance sheets are as follows:


(in thousands)	June 30, 2025
Assets
Current assets
Cash and cash equivalents	$	4,353
Accounts receivable, net	5,881

Total current assets	10,234
Other property and equipment, net	43,686
Total assets	$	53,920

Liabilities
Current liabilities
Accounts payable and accrued liabilities	$	4,609
Total liabilities	$	4,609

The amounts shown in the above table exclude intercompany balances.

Noncontrolling Interest

Pursuant to the BKV-CIP JV Agreement the Class B Units are not mandatorily redeemable or currently redeemable, but become exercisable with the passage of time, which is on the second anniversary of the BKV-CIP JV Agreement, or May 8, 2027. The Company determined that there is an embedded put option in the Class B Units, which does not meet the derivative accounting criteria, and is not within control of the Company. Therefore, the shares of the BKV-CIP Joint Venture's Class B Units have been classified as noncontrolling interest within mezzanine equity on the Company's condensed consolidated balance sheets. The redemption value of the Class B Units is based on a multiple investment on capital equal to 1.65, which may be redeemed on the second anniversary date. The contributions from the Class B Member are accreted to the redemption value over a 2-year period (using the effective interest method) with the accretion accounted for as a dividend paid to the Class B Member.

As of June 30, 2025, distributions payable to noncontrolling interest was $6.9 million, which represents 49% of the Section 45Q tax credits generated by BKV dCarbon Ventures in 2024. The distributions payable is included in accounts payable and accrued liabilities on the condensed consolidated balance sheets.

Note 11 - Commitments and Contingencies

From time to time, the Company may be subject to various claims, title matters, and legal proceedings arising in the ordinary course of business, including environmental contamination claims, personal injury and property damage claims, claims related to joint interest billings and other matters under natural gas operating agreements, and other contractual disputes. The Company maintains general liability and other insurance to cover some of these potential liabilities. All known liabilities are fully accrued based on the Company's best estimate of the potential loss. While the outcome and impact on the Company cannot be predicted with certainty, results may change in future periods. For the periods presented in the condensed consolidated financial statements, the Company believes that its ultimate liability, with respect to any such matters, will not have a significant impact or material adverse effect on its financial positions, results of operations, or cash flows. Results of operations and cash flows, however, could be significantly impacted in the reporting periods in which such matters are resolved.

As a part of the consideration paid for the Devon Barnett Acquisition, additional cash consideration would be required to be paid by the Company if certain thresholds were met for average Henry Hub natural gas and WTI crude oil prices for each of the calendar years during the period beginning January 2021 through December 31, 2024 (the “Devon Barnett Earnout”). Average Henry Hub payouts and threshold were as follows: $2.75/MMBtu $20.0 million, $3.00/MMBtu $25.0 million, $3.25/MMBtu $35.0 million, and $3.50/MMBtu $45.0 million; average WTI payouts and thresholds are as follows for these periods: $50.00/Bbl $10.0 million, $55.00/Bbl $12.5 million, $60.00/Bbl $15.0 million, and $65.00/Bbl $20.0 million. Payments were due in the


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month following the end of the respective measurement period for which the hurdle rates were set. As of December 31, 2024, the final portion of the arrangement was considered to be settled resulting in a settlement of $20.0 million, which is reflected as contingent consideration payable within current liabilities on the condensed consolidated balance sheets, and was paid on January 8, 2025. As described in Note 4 - Fair Value Measurements and Note 5 - Derivative Instruments, the contingent consideration was accounted for as a derivative instrument. Management uses NYMEX forward pricing estimates for both Henry Hub and WTI hurdle rates and Monte Carlo simulations to determine the fair value of the contingent consideration. For the three and six months ended June 30, 2024, the changes in the fair value of the contingent consideration were a loss of $0.7 million and a gain of $3.9 million, respectively. These changes in the fair value during this period impacted the associated liability on the condensed consolidated balance sheets and the changes were recognized in the gains (losses) on contingent consideration liabilities on the condensed consolidated statements of operations.

In conjunction with the Exxon Barnett Acquisition, additional cash consideration would have been required to be paid by the Company if certain thresholds for future Henry Hub natural gas prices were met for the year ended December 31, 2024. Based on the thresholds for this period, no payout was required. As of December 31, 2024, the fair value of the contingent consideration was zero. The changes in the fair value of the contingent consideration for the three and six months ended June 30, 2024 were gains of $0.2 million and $2.2 million, respectively. These changes in the fair value during this period reduced the associated liability on the condensed consolidated balance sheets and recognition of the gains were recognized in the gains (losses) on contingent consideration liabilities on the condensed consolidated statements of operations. Refer to Note 4 - Fair Value Measurements for the valuation methodology and associated inputs.

The Company has volume commitments in the form of gathering, processing, and transportation agreements with various third parties that require delivery of 998,646,828 dekatherms of natural gas. The significant majority of the agreements terminate by 2029, with one agreement extending through 2036. As of June 30, 2025, the aggregate undiscounted future payments required under these contracts total $287.6 million.

A summary of the Company's commitments, excluding contingent consideration, as of June 30, 2025, is provided in the following table:


(in thousands)	2025		2026		2027		2028		2029		Thereafter		Total
RBL Credit Agreement	$	—	$	—	$	—	$	200,000	$	—	$	—	$	200,000
Interest payable	1,007		—		—		—		—		—		1,007


Operating lease payments	629		1,047		908		924		947		3,662		8,117
Volume commitments	34,659		67,615		58,959		53,144		34,257		38,929		287,563
Total	$	36,295	$	68,662	$	59,867	$	254,068	$	35,204	$	42,591	$	496,687

Note 12 - Income Taxes

The effective tax expense (benefit) rates for the three months ended June 30, 2025 and 2024 were 21.0% and (32.2)%, respectively, and for the six months ended June 30, 2025 and 2024 were (5.2)% and (29.6)%, respectively. For the three and six months ended June 30, 2025 and 2024, the difference in the effective tax rate from the U.S. statutory federal income tax rate of 21.0% was primarily due to the Company benefiting from certain tax credits under the Section 45Q tax credits from the injection of CO2 waste in the Barnett Zero CCUS project well, from Section 45I tax credits from marginal well production, and deferred tax balance remeasurement for Pennsylvania, partially offset by the expense related to executive compensation limitation. The difference in the effective tax rate from the U.S. statutory federal income tax rate for the three and six months ended June 30, 2024 also included state apportionment changes.

Note 13 - Earnings Per Share

Basic net income (loss) attributable to BKV per common share for each period is calculated by dividing net income (loss) attributable to BKV by the basic weighted average number of common shares outstanding during the period. Diluted net income (loss) per common share is calculated by dividing net income (loss) attributable to BKV by the diluted weighted average number of common shares outstanding for the respective period. Any remeasurement of the accretion to redemption value of the Class B Units subject to possible redemption was considered to be dividends paid to the noncontrolling interest. Diluted weighted average number of common shares outstanding and the dilutive effect of potential common shares is calculated using the treasury method. The Company includes potential shares of common stock for PRSUs and TRSUs in the calculation of diluted weighted average shares outstanding based on the number of common shares that would be issuable if the end of the reporting period was also the


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end of the performance period. During periods in which the Company incurred a net loss, diluted weighted average common shares outstanding were equal to basic weighted average of common shares outstanding because the effects of all potential common shares was anti-dilutive.

The calculation of basic and diluted net income (loss) per common share attributable to BKV for the three and six months ended June 30, 2025 and 2024:


	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands, except per share amounts)	2025		2024		2025		2024
Net income (loss) attributable to BKV	$	104,572	$	(59,697)	$	25,906	$	(98,282)
Accretion of Class B Units to redemption value	(281)		—		(281)		—
Net income (loss) including accretion of Class B Units to redemption value	$	104,291	$	(59,697)	$	25,625	$	(98,282)

Basic weighted average common shares outstanding	84,710		66,349		84,708		66,318
Add: dilutive effect of TRSUs	124		—		81		—
Add: dilutive effect of PRSUs	—		—		—		—
Diluted weighted average of common shares outstanding	84,834		66,349		84,789		66,318
Weighted average number of outstanding securities excluded from the calculation of diluted loss per share
TRSUs	—		302		—		292
PRSUs	—		3,890		—		3,895

Net income (loss) per common share attributable to BKV:
Basic	$	1.23	$	(0.90)	$	0.30	$	(1.48)
Diluted	$	1.23	$	(0.90)	$	0.30	$	(1.48)

Note 14 - Subsequent Events

On July 4, 2025, the One Big Beautiful Bill Act ("OBBBA") was signed into law. The OBBBA provides for permanent extension of various provisions of the 2017 Tax Cuts and Jobs Act including 100% bonus depreciation, the ability to immediately expense domestic research costs, modification of the taxable income base used for the limitation of interest expense, and a phase out of certain clean energy credits. We are currently assessing the impact of the OBBBA on our financial statements.

As of June 30, 2025, the Company was actively implementing a new enterprise resource planning ("ERP") system and had capitalized $6.9 million in software costs. As of June 30, 2025, there were no known strategic concerns, delays, or indications of pausing. On July 31, 2025, the Company made the decision to pause the implementation of this ERP system, and as of August 12, 2025, is in the process of evaluating ERP systems that better align with the company-needs. This evaluation may require the Company to write off the majority of the capitalized software costs, along with other related costs.

On August 7, 2025, BKV Upstream Midstream, and solely for the limited purposes set forth therein, the Company, entered into a purchase and sale agreement to acquire approximately 1,000 operated wells and 200 non-operated wells in the Barnett for aggregate consideration of $370.0 million, subject to adjustment. The purchase price for the Bedrock acquisition is expected to consist of cash consideration of approximately $260.0 million and a number of BKV's common stock valued at up to $110.0 million, subject to a 60-day lock-up provision. This acquisition is expected to close late in the third quarter or early in the fourth quarter of 2025, subject to customary closing conditions.


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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated financial statements and related notes included in Item 1 of Part I, Financial Statements in this report on Form 10-Q and our audited consolidated financial statements and related notes, including “Management's Discussion and Analysis of Financial Condition and Results of Operations” for the year ended December 31, 2024 included in our 2024 Annual Report on Form 10-K filed on March 31, 2025. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expectations. We disclaim any duty to publicly update any forward-looking statements except as otherwise required by applicable law.

In this section, references to “BKV,” the “Company,” “we,” “us,” and “our” refer to BKV Corporation and its subsidiaries, unless otherwise indicated or the context otherwise requires. For more information on our organizational structure, see Note 1 - Business and Basis of Presentation to our condensed consolidated financial statements included in Item 1 of Part I of this report.

Overview

We are a forward thinking, growth driven energy company focused on creating value for our stockholders through the organic development of our properties as well as accretive acquisitions. Our core business is to produce natural gas from our owned and operated upstream businesses, which are supported by our four business lines: natural gas production; our natural gas midstream business; power generation; and CCUS. We expect our owned and operated upstream and natural gas midstream businesses to achieve net zero Scope 1 and Scope 2 emissions by the early 2030s, and net zero Scope 1, 2, and 3 emissions by the late 2030s. We maintain a “closed-loop” approach to our net zero emissions goal through the operation of our four business lines. We are committed to vertically integrating portions of our business to reduce costs and improve overall commercial optimization of the full value chain. For instance, in the Barnett, our natural gas production is gathered and transported in part through our midstream systems and we commenced sequestration operations at our first CCUS project in November 2023. We expect our second and third CCUS projects to commence sequestration activities in the first half of 2026 and are evaluating a robust backlog of actionable CCUS opportunities. We believe that our differentiated business model, net zero emissions focus, highly experienced management team and technology-driven approach to operating our business will enable us to create stockholder value.

Recent Developments

•Partnership in the BKV-CIP Joint Venture. As previously announced, on May 8, 2025, BKV dCarbon Ventures, together with C Squared Solutions, Inc. (the “Class B Member”), a subsidiary of the Energy Transition Fund managed by Copenhagen Infrastructure Partners (CIP), and, for the limited purposes specified therein, BKV Corporation, entered into the BKV-CIP JV Agreement forming BKV dCarbon Project, LLC (the “BKV-CIP Joint Venture”) for the purpose of developing CCUS projects. Also on May 8, 2025 and contemporaneously with their entry into the BKV-CIP JV Agreement, the parties thereto also entered into certain ancillary agreements related to the joint venture. BKV dCarbon Ventures has contributed to the BKV-CIP Joint Venture its ownership of the Barnett Zero Project and Eagle Ford Project and related assets (including the CCUS projects held by such entities) and has committed to future contributions of certain CCUS projects, related assets, and/or cash, in exchange for an interest in the BKV-CIP Joint Venture and Class A Units at $10.00 per share. The Class B Member committed up to an initial $500.0 million for use by the BKV-CIP Joint Venture in construction and operating new CCUS projects across the United States in exchange for up to a 49% interest in the BKV-CIP Joint Venture and 49% of the Section 45Q tax credits generated in 2024 through the date of the BKV-CIP JV Agreement.

•New CCUS Project. On July 21, 2025, we executed an agreement with a diversified midstream energy company to develop a new carbon capture and sequestration project at an existing operating natural gas processing plant in East Texas, which is expected to be operational by January 1, 2027. Under the terms of the agreement, we forecast approximately 70,000 metric tons per year of CO2 waste stream could be captured by the plant, which would then be delivered via BKV's Class II injection well to be compressed, transported, and permanently sequestered. The co-located Class II injection well eliminates the need to invest in a high-pressure pipeline. This project will be owned by BKV, but may be transferred to the BKV-CIP Joint Venture.

•Evaluation of Enterprise Resource Planning (“ERP”) System. On July 31, 2025, management made the strategic decision to pause its ERP system implementation, which began development in the fourth quarter of 2024. The decision was driven by Company growth and a strategic reassessment of our evolving operational and financial needs. As of August 12, 2025, we are in the process of evaluating ERP systems that better align with our company-needs. As of


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June 30, 2025, we had $6.9 million of capitalized software costs, and the evaluation may require us to write off the majority of this amount along with other related costs.

•Bedrock Acquisition. On August 7, 2025, BKV Upstream Midstream, and solely for the limited purposes set forth therein, BKV Corporation, entered into an agreement to acquire all of the equity interests in Bedrock Production, LLC (“Bedrock”), for a purchase price of $370.0 million, subject to customary purchase price adjustments. The purchase price for the Bedrock acquisition is expected to consist of cash consideration of approximately $260.0 million and a number of BKV's common stock valued at up to $110.0 million, subject to a 60-day lock-up provision. Upon the acquisition of Bedrock, which holds Bedrock Energy Partners' Barnett shale assets, we will acquire approximately 97,000 net acres, or 108 MMcfe/d of production (approximately 63% natural gas), 1,121 producing locations, nearly 1 Tcfe of 1P reserves (using NYMEX strip pricing), and 50 new drill locations with an assumed 10,000 lateral length with accretive natural gas price break-evens compared to our existing inventory, and 80 low cost refrac locations. The Bedrock acquisition is expected to close late in the third quarter or early in the fourth quarter of 2025, subject to customary closing conditions.

Operational and Financial Highlights

Below are some highlights of our operating and financial results three and six months ended June 30, 2025.

•Production of natural gas, NGLs, and oil was 73.8 Bcfe, or 811.0 MMcfe/d and 142.3 Bcfe, or 786.2 MMcfe/d, respectively.

•Average realized product prices, excluding the impact of settled derivatives, were $2.71 per Mcfe and $2.92 per Mcfe, respectively.

•Production revenues were $199.7 million and $415.9 million, respectively, and midstream revenues were $2.7 million and $5.5 million, respectively.

•Lease operating expense was $32.7 million, or $0.44 per Mcfe and $66.4 million, or $0.47 per Mcfe, respectively.

•Net income attributable to BKV was $104.6 million and $25.9 million, respectively.

•Net cash provided by operating activities for the six months ended June 30, 2025 was $98.8 million.

•Accrued capital expenditures for the six months ended June 30, 2025 were $136.8 million.

Factors That Affect Comparability of Our Financial Condition and Results of Operations

Our business depends on many factors, primarily commodity prices, market supply and demand for natural gas, NGLs, and oil, upstream capital costs, and production costs. We continually monitor domestic and global factors which may cause our actual results of operations to differ from historical results or expected outlook.

Commodity Pricing. The natural gas and NGL industry is cyclical and commodity prices are highly volatile, and we expect these prices to continue to remain volatile in the near future. In order to manage our market exposure of price volatility, we utilize derivative contracts in connection with our natural gas operations to provide an economic hedge of our exposure to commodity price risks associated with anticipated future natural gas and NGL production. However, there are still market risks beyond our control that may impact our financial condition, results of operations, and cash flows.

Supply, Demand, Market Risk, and the Impact on Natural Gas, NGL, and Oil Prices. Natural gas and oil prices are subject to large fluctuations in response to relatively minor changes in the demand for natural gas, NGLs, and oil. Prices are affected by current and expected supply and demand dynamics, including the level of drilling, completion, and production activities by other natural gas production companies, global industry-wide supply chain disruptions, widespread shortages of labor, material, and services, the ability to agree and maintain production levels by members of OPEC and other oil producing countries, and political instability of other energy producing countries, resulting in increased supply in the global market. Other factors impacting supply and demand include weather conditions (including severe weather events), pipeline capacity constraints, inventory storage levels, basis differentials, export capacity, supply chain quality and availability, strength of the U.S. dollar as well as other factors, the majority of which are outside of our control.

Upstream Capital Costs. Businesses engaged in the exploration and production of natural gas and NGLs, such as ours, face the challenge of natural production declines. As initial reservoir pressures are depleted, natural gas and NGL production from a


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given well naturally decreases. Thus, as does any natural gas exploration and production company, we deplete part of our asset base with each unit of natural gas and NGLs we produce. We attempt to overcome this natural decline by drilling and refracturing to unlock additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production in a cost-effective manner, through development of existing assets and acquisitions. Our ability to make capital expenditures to increase production from our existing reserves and to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to access capital in a cost-effective manner and to timely obtain drilling permits and regulatory approvals.

Other factors significantly affecting our financial condition and results of operations include, among others:

•success in drilling new wells;

•the availability of attractive acquisition opportunities and our ability to execute them;

•the amount of capital we invest in the leasing and development of our properties;

•facility or equipment availability and unexpected downtime; and

•delays imposed by or resulting from compliance with regulatory requirements.

Production Volumes.

The following table presents our historical production volumes for the periods presented:


	Three Months Ended June 30,		Six Months Ended June 30,
	2025	2024	2025	2024
Production Data
Natural gas (MMcf)	58,328	57,113	112,451	116,756
NGLs (MBbls)	2,535	2,502	4,877	4,987
Oil (MBbls)	44	24	97	52
Total volumes (MMcfe)	73,802	72,269	142,295	146,990
Average daily total volumes (MMcfe/d)	811.0	794.2	786.2	807.6

Sources of Revenues

Currently, substantially all of our revenues are derived from the sale of our natural gas production and the NGLs that are extracted from processing our natural gas, though we also generate a portion of our revenues from the sale of crude oil, midstream and surface operations, and certain marketing revenue and other income. Our midstream and surface operations primarily support our own exploration and production operations, with revenues generated primarily from fees charged for midstream and surface services, including transportation, freshwater sourcing and disposal, and other services to us and our affiliates and, to a lesser extent, third parties.

Realized Commodity Prices

NYMEX Henry Hub, for gas prices, and NYMEX WTI, for oil prices, are widely used benchmarks for the pricing of natural gas and oil in the United States. The price we receive for our natural gas and oil production is generally different than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors. As such, our revenues are sensitive to the price of the underlying commodity to which they relate. For further discussion on our derivative contracts, see Note 5 - Derivative Instruments to the unaudited condensed consolidated financial statements. The following is a comparison of average pricing excluding and including the effects of derivatives:


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	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Average prices:
Natural gas ($/Mcf):
Average NYMEX Henry Hub price	$	3.44	$	1.94	$	3.55	$	2.07
Average natural gas realized price (excluding derivatives)	$	2.67	$	1.45	$	2.88	$	1.53
Average natural gas realized price (including derivatives) (1)	$	2.83	$	1.98	$	2.84	$	1.99
Differential	$	(0.77)	$	(0.49)	$	(0.67)	$	(0.54)
NGLs ($/Bbl):
Average NGL realized price (excluding derivatives)	$	16.42	$	16.47	$	17.70	$	16.97
Average NGL realized price (including derivatives) (1)	$	16.41	$	16.93	$	16.64	$	17.21
Oil ($/Bbl):
Average oil realized price	$	57.66	$	74.92	$	61.82	$	71.81
High and low daily spot prices:
Natural gas ($/Mcf):
High NYMEX Henry Hub	$	4.21	$	2.80	$	9.86	$	13.20
Low NYMEX Henry Hub	$	2.65	$	1.36	$	2.65	$	1.25
Oil ($/Bbl):
High NYMEX WTI	$	75.89	$	87.69	$	80.73	$	87.69
Low NYMEX WTI	$	58.50	$	74.27	$	58.50	$	70.62

(1) Impact of derivatives prices excludes $13.3 million of gains on derivative contract terminations for the six months ended June 30, 2024.


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Results of Operations

Comparison of the Three Months Ended June 30, 2025 and 2024

Operating Revenues and Operating Income

Our operating revenues and other income from operations include the activity from the sale of natural gas, NGLs, and oil, midstream revenues, gains and losses on our derivative contracts and on the sale of our business, marketing revenues, Section 45Q tax credits, related party revenues, and other income from operations. The following table provides information on our revenues and other operating income for the periods presented:


	Three Months Ended June 30,
(in thousands, other than percentages)	2025		2024		$ Change		% Change
Revenues
Natural gas revenues	$	155,562	$	82,840	$	72,722	88	%
NGL revenues	41,630		41,216		414		1	%
Oil revenues	2,537		1,798		739		41	%
Midstream revenues	2,739		3,378		(639)		(19)	%
Derivative gains (losses), net	112,208		(7,486)		119,694		*
Marketing revenues	1,372		2,046		(674)		(33)	%
Gain on sale of business	—		5,968		(5,968)		(100)	%
Section 45Q tax credits	2,574		3,644		(1,070)		(29)	%
Related party revenues	425		1,101		(676)		(61)	%
Other	2,997		1,693		1,304		77	%
Total revenues and other operating income	$	322,044	$	136,198
*Percentage not meaningful

Natural Gas Revenues

Our natural gas revenues increased by approximately $72.7 million, or 88%, to $155.6 million for the three months ended June 30, 2025, from $82.8 million for the three months ended June 30, 2024. The impact of commodity price increases, excluding the effect of derivative settlements, provided a $71.0 million increase in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes). The increase was also due to slightly higher production volumes during the three months ended June 30, 2025, which accounted for a $1.7 million increase in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price).

NGL Revenues

Our NGL revenues increased by approximately $0.4 million, or 1%, to $41.6 million for the three months ended June 30, 2025, from $41.2 million for the three months ended June 30, 2024. The increase was due to slightly higher production volumes during the three months ended June 30, 2025, which accounted for a $0.5 million increase in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price). The increase was slightly offset by commodity price decreases, excluding the effect of derivative settlements, which accounted for a $0.1 million decrease in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes).

Oil Revenues

Our oil revenues increased by approximately $0.7 million, or 41%, to $2.5 million for the three months ended June 30, 2025, from $1.8 million for the three months ended June 30, 2024. The increase was primarily due to higher production volumes during the three months ended June 30, 2025, which accounted for a $1.5 million increase in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price). The increase was offset by the impact of commodity price decreases, excluding the effect of derivative settlements, which accounted for a $0.8 million decrease in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes).

Midstream Revenues


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Our midstream revenues decreased by approximately $0.6 million, or 19%, to $2.7 million for the three months ended June 30, 2025, from $3.4 million for the three months ended June 30, 2024. This decrease was primarily due to the divestiture of Chaffee as we sold our Repsol Midstream Interest in connection with this sale.

Derivative Gains (Losses), Net

For the three months ended June 30, 2025, we had net realized and unrealized gains on derivative contracts of $112.2 million compared to net realized and unrealized losses on derivative contracts of $7.5 million for the three months ended June 30, 2024. The increase in gains for the three months ended June 30, 2025 were from our open derivative positions, which were in more of an unrealized gain position of $102.9 million compared to the three months ended June 30, 2024, which was in an unrealized loss position of $39.0 million. The increase in unrealized gains during the current period was due to significant short-term declines in natural gas prices, and in the same period in the prior year, there were more contracts in a liability position. The increased gains on our derivative contracts were offset by a decrease in realized gains of $22.2 million to $9.3 million for the three months ended June 30, 2025 compared to realized gains of $31.5 million in the same period in 2024, which were due to higher natural gas prices in the current period compared to the same period in the prior year.

Marketing Revenues

Our marketing revenues decreased by approximately $0.7 million, or 33% to $1.4 million for the three months ended June 30, 2025 from $2.0 million for the three months ended June 30, 2024. Our marketing revenues are derived under our marketing agreement with a third party pursuant to which we receive a fixed percentage of all net income realized in the resale of our and other producers’ hydrocarbons. The decrease in marketing revenues during the three months ended June 30, 2025 was primarily due to a lower peak pricing environment compared to the same period in 2024.

Gain on Sale of Business

For the three months ended June 30, 2024, we sold our wholly-owned subsidiary, Chaffee for $103.2 million, net of third-party transaction costs. The assets sold had an approximate carrying value of $97.3 million, which resulted in a gain on the sale of Chaffee of $6.0 million.

Section 45Q Tax Credits

We generated $2.6 million in Section 45Q tax credits during the three months ended June 30, 2025 related to CO2 waste sequestration activities under our Barnett Zero Project compared to $3.6 million during the three months ended June 30, 2024. The period-over-period decrease was due to lower volumes of CO2 waste sequestered in 2025, which resulted from operational maintenance conducted by the supplier in April and May 2025.

Related Party Revenues

Our related party revenues were $0.4 million for the three months ended June 30, 2025, compared to $1.1 million for the three months ended June 30, 2024. The decrease in related party revenues was due to a $0.7 million decrease in operating fee income with BKV-BPP Power, attributable to lower contracted rates.

Other Revenues

Other revenues primarily includes the sale of third-party natural gas, which was $2.9 million for the three months ended June 30, 2025 compared to $1.5 million for the three months ended June 30, 2024. The period-over-period increase was primarily due to an increase in third-party gas sales of $1.3 million.

Operating Expenses

Our operating expenses reflect costs incurred in the development, production, and sale of natural gas, NGLs, and oil. The following table provides information on our operating expenses:


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	Three Months Ended June 30,
(in thousands, other than percentages and average costs)	2025		2024		$ Change		% Change
Operating expenses
Lease operating and workover	$	34,176	$	34,172	$	4	0%
Taxes other than income	13,404		9,850		3,554		36%
Gathering and transportation costs	63,026		53,714		9,312		17%
Depreciation, depletion, amortization, and accretion	38,044		59,313		(21,269)		(36)%
General and administrative	30,516		19,296		11,220		58%
Other	14,480		3,034		11,446		*
Total operating expense	$	193,646	$	179,379
Average costs per Mcfe
Lease operating and workover	$	0.46	$	0.48	$	(0.02)	(4)%
Taxes other than income	0.18		0.14		0.04		29%
Gathering and transportation costs	0.85		0.74		0.11		15%
Depreciation, depletion, amortization, and accretion	0.52		0.82		(0.30)		(37)%
General and administrative	0.41		0.27		0.14		52%
Other	0.20		0.04		0.16		*
Total	$	2.62	$	2.49
*Percentage not meaningful

Lease Operating and Workover

The following table summarizes our components of lease operating expenses for the periods presented:


	Three Months Ended June 30,
	2025				2024				$ Change		% Change
(in thousands, other than percentages and average costs)	Amount		Per Mcfe		Amount		Per Mcfe
Lease operating expenses	$	32,677	$	0.44	$	32,888	$	0.46	$	(211)	(1)	%
Workover expenses	1,499		0.02		1,284		0.02		215		17	%
Total lease operating and workover expense	$	34,176	$	0.46	$	34,172	$	0.48	$	4	0	%

Lease operating and workover expenses were $34.2 million, or $0.46 per Mcfe, for the three months ended June 30, 2025, which was consistent for the three months ended June 30, 2024 of $34.2 million, or $0.48 per Mcfe. Lease operating expenses during the three months ended June 30, 2025 compared to the same period in 2024 increased by $1.3 million in our Pad of the Future activity, compression movement, and other individually immaterial increases, offset by the timing of inspection fees and a decrease in water and disposal costs of $0.8 million, and $0.5 million, respectively.

Taxes Other Than Income

Taxes other than income were $13.4 million, or $0.18 per Mcfe, for the three months ended June 30, 2025, which was an increase of approximately $3.6 million, or 36%, from $9.8 million, or $0.14 per Mcfe, for the three months ended June 30, 2024. The increase in taxes other than income during the three months ended June 30, 2025 compared to 2024 was due to increases in production taxes of $4.2 million in the Barnett. This was offset by decreases in ad valorem and property taxes associated with our operations in the Barnett and NEPA of $0.5 million and $0.1 million, respectively. Certain ad valorem and production taxes are not applicable to our NEPA properties.

Gathering and Transportation


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Gathering and transportation expenses in the Barnett were $63.0 million, or $0.85 per Mcfe, for the three months ended June 30, 2025, which was an increase of approximately $9.3 million, or 17%, from $53.7 million, or $0.74 per Mcfe, for the three months ended June 30, 2024. This increase was primarily driven by natural gas and NGL rate increases of $5.7 million, and $1.8 million, respectively, and increased natural gas and NGL production of $2.4 million and $0.2 million, respectively. This was offset by a decrease in the gathering costs on our outsourced contracts with our midstream business of $0.8 million.

Depreciation, Depletion, Amortization, and Accretion

Depreciation, depletion, amortization, and accretion was $38.0 million, or $0.52 per Mcfe, for the three months ended June 30, 2025, which was a decrease of approximately $21.3 million, or 36%, from $59.3 million, or $0.82 per Mcfe, for the three months ended June 30, 2024. The decrease in depreciation, depletion, amortization, and accretion during the three months ended June 30, 2025 compared to the three months ended June 30, 2024 was primarily due to a depletion rate adjustment in 2025, which was driven by higher reserves.

General and Administrative

General and administrative expenses were $30.5 million, or $0.41 per Mcfe, for the three months ended June 30, 2025, which was an increase of approximately $11.2 million, or 58%, from $19.3 million, or $0.27 per Mcfe, for the three months ended June 30, 2024. The increase in general and administrative expenses during the three months ended June 30, 2025 compared to the three months ended June 30, 2024 was due to increases from Company-wide growth initiatives of $6.7 million in contract labor, employee-based compensation, and employee expenses, $3.0 million in consulting expenses, and $1.8 million in severance costs, offset by a decrease of $0.3 million in information technology-related expenses.

Other Operating Expenses

Other operating expenses were $14.5 million, or $0.20 per Mcfe, for the three months ended June 30, 2025, which was an increase of approximately $11.4 million, from $3.0 million, or $0.04 per Mcfe, for the three months ended June 30, 2024. The increase in other operating expenses during the three months ended June 30, 2025 compared to the same period in 2024 was due to $3.1 million of costs related to the CCUS equity raise, $2.1 million increase in third-party natural gas purchases due to increased volumes and natural gas prices, $2.1 million of a deficiency payment incurred under our minimum volume commitments on our midstream pipeline, $1.6 million in CCUS transaction fees, $1.1 million in a project write-off, $0.7 million in increased emissions monitoring costs, and $0.4 million in legal settlements. This was offset by a decrease of $0.2 million of CCUS operating expenses for CO2 purchases for sequestration due to operational maintenance conducted by the supplier in April and May 2025.

Other Income (Expense)

Gains (losses) on contingent consideration liabilities. For the three months ended June 30, 2024, we recognized a loss on contingent consideration liabilities accruing as an earnout obligation under the purchase agreements executed in connection with the Devon Barnett Acquisition and the Exxon Barnett Acquisition. The loss on contingent consideration liabilities was $0.5 million for the three months ended June 30, 2024, and consisted of a loss of $0.7 million and a gain of $0.2 million from the Devon Barnett Acquisition and the Exxon Barnett Acquisition, respectively. The contingent considerations under these purchase agreements expired in 2024.

Earnings (losses) from equity affiliate. Earnings from our equity affiliate were $9.1 million for the three months ended June 30, 2025, which was a change of $24.3 million, from $15.3 million of losses from our equity affiliate during the three months ended June 30, 2024. Earnings (losses) from our equity affiliate are related to our investment in, and our proportionate share in the income or losses of the BKV-BPP Power Joint Venture.

Interest expense. Interest expense was $5.5 million for the three months ended June 30, 2025, which was a decrease of $9.7 million, from $15.2 million for the three months ended June 30, 2024. The decrease in interest expense during the three months ended June 30, 2025 was primarily due to lower interest rates incurred during the three months ended June 30, 2025 on our RBL Credit Facility, which we entered into on June 11, 2024, compared to the interest rates on our Term Loan Credit Agreement and Revolving Credit Facilities during the three months ended June 30, 2024.

Interest expense, related party. Interest expense from our related party borrowings with BNAC was $1.9 million for the three months ended June 30, 2024, which was paid down in June 2024.

Interest income. Interest income was $0.2 million for the three months ended June 30, 2025, which was a decrease of $1.6 million, from $1.8 million for the three months ended June 30, 2024. The decrease was due to the cessation of interest earned on


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restricted cash following the repayment of the Term Loan Agreement in June 2024, which had previously funded the debt service reserve account.

Income tax benefit (expense). For the three months ended June 30, 2025, we had an income tax expense of $27.9 million, which was a change of $56.3 million, from a $28.4 million in income tax benefit for the three months ended June 30, 2024. The period-over period change was primarily due to a pre-tax income for the three months ended June 30, 2025, compared to a pre-tax loss during the three months ended June 30, 2024.


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Results of Operations

Comparison of the Six Months Ended June 30, 2025 and 2024

Operating Revenues and Operating Income

Our operating revenues and other income from operations include revenues from the sale of natural gas, NGLs, and oil, midstream revenues, gains and losses on our derivative contracts and on the sale of our business, marketing revenues, Section 45Q tax credits, related party revenues, and other income from operations. The following table provides information on our revenues and other operating income for the periods presented:


	Six Months Ended June 30,
(in thousands, other than percentages)	2025		2024		$ Change		% Change
Revenues
Natural gas revenues	$	323,545	$	179,175	$	144,370	81	%
NGL revenues	86,313		84,632		1,681		2	%
Oil revenues	5,997		3,734		2,263		61	%
Midstream revenues	5,510		7,506		(1,996)		(27)	%
Derivative losses, net	(39,983)		(11,165)		(28,818)		*
Marketing revenues	7,857		6,967		890		13	%
Gain on sale of business	—		5,968		(5,968)		(100)	%
Section 45Q tax credits	5,881		5,973		(92)		(2)	%
Related party revenues	851		2,203		(1,352)		(61)	%
Other	4,893		3,119		1,774		57	%
Total revenues and other operating income	$	400,864	$	288,112
*Percentage not meaningful

Natural Gas Revenues

Our natural gas revenues increased by approximately $144.4 million, or 81% to $323.5 million for the six months ended June 30, 2025, from $179.2 million for the six months ended June 30, 2024. The impact of commodity price increases, excluding the effect of derivative settlements, provided a $151.0 million increase in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes). The increase was slightly offset by lower production volumes during the six months ended June 30, 2025, primarily from the sale of Chaffee and certain non-operated assets held by Chelsea, for a $6.6 million decrease in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price).

NGL Revenues

Our NGL revenues increased by approximately $1.7 million, or 2% to $86.3 million for the six months ended June 30, 2025, from $84.6 million for the six months ended June 30, 2024. The increase was due to the impact of commodity price increases, excluding the effect of derivative settlements, which accounted for a $3.5 million increase in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes). The increase was offset by lower production volumes during the six months ended June 30, 2025, which accounted for a $1.9 million decrease in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price).

Oil Revenues

Our oil revenues increased by approximately $2.3 million, or 61%, to $6.0 million for the six months ended June 30, 2025, from $3.7 million for the six months ended June 30, 2024. The increase was due to higher production volumes during the six months ended June 30, 2025, which accounted for a $3.2 million increase in period-over-period revenues (calculated as the change in period-to-period volumes times the prior period average price). The increase was offset by the impact of commodity price decreases, excluding the effect of derivative settlements, which accounted for a $1.0 million decrease in period-over-period revenues (calculated as the change in the period-to-period average price times current period production volumes).

Midstream Revenues


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Our midstream revenues decreased by approximately $2.0 million, or 27% to $5.5 million for the six months ended June 30, 2025, from $7.5 million for the six months ended June 30, 2024. This decrease was primarily due to the divestiture of Chaffee of $2.0 million as we sold our Repsol Midstream Interest in connection with this sale.

Derivative Gains (Losses), Net

For the six months ended June 30, 2025, we had net realized and unrealized losses on derivative contracts of $40.0 million compared to net realized and unrealized losses on derivative contracts of $11.2 million for the six months ended June 30, 2024. The losses during the six months ended June 30, 2025 was primarily attributable to an increase in the forward natural gas curve, resulting in unrealized losses of $31.1 million and realized losses of $8.9 million. During the six months ended June 30, 2024, we had unrealized losses of $79.1 million, which was primarily attributable to the unrealized loss on the call option we sold in January 2024. This was offset by realized gains during the six months ended June 30, 2024 of $67.9 million due to lower natural gas prices.

Marketing Revenues

Our marketing revenues increased by approximately $0.9 million to $7.9 million for the six months ended June 30, 2025 from $7.0 million for the six months ended June 30, 2024. Our marketing revenues are derived under our marketing agreement with a third party pursuant to which we receive a fixed percentage of all net income realized in the resale of our and other producers’ hydrocarbons. The increase in marketing revenues during the six months ended June 30, 2025 was primarily due to a higher pricing environment compared to the same period in 2024.

Gain on Sale of Business

For the six months ended June 30, 2025, we sold our wholly-owned subsidiary, Chaffee for $103.2 million, net of third-party transaction costs. The assets sold had an approximate carrying value of $97.3 million, which resulted in a gain on the sale of Chaffee of $6.0 million.

Section 45Q Tax Credits

We generated $5.9 million in Section 45Q tax credits during the six months ended June 30, 2025 related to CO2 waste sequestration activities under our Barnett Zero Project, compared to $6.0 million during the six months ended June 30, 2024. The decrease period-over-period was due to less CO2 waste sequestered in 2025 compared to the prior period from operational maintenance in April and May 2025.

Related Party Revenues

Our related party revenues were $0.9 million for the six months ended June 30, 2025 compared to $2.2 million for the six months ended June 30, 2024. The decrease in related party revenues was due to a $1.4 million decrease in operating fee income with BKV-BPP Power, attributable to lower contracted rates.

Other Revenues

Other revenues includes the impairment on the asset held for and the sale of third-party natural gas. Other revenues were $4.9 million for the six months ended June 30, 2025 compared to $3.1 million for the six months ended June 30, 2024. The period-over-period increase was due to an increase in third-party gas of $3.8 million, and an increase in the gain on sale of assets of $0.4 million, offset by the impairment on the asset held for sale of $2.4 million.

Operating Expenses

Our operating expenses reflect costs incurred in the development, production and sale of natural gas, NGLs, and oil. The following table provides information on our operating expenses:


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	Six Months Ended June 30,
(in thousands, other than percentages and average costs)	2025		2024		$ Change		% Change
Operating expenses
Lease operating and workover	$	69,231	$	68,640	$	591	1%
Taxes other than income	23,626		21,215		2,411		11%
Gathering and transportation costs	118,819		113,105		5,714		5%
Depreciation, depletion, amortization, and accretion	78,014		111,479		(33,465)		(30)%
General and administrative	55,773		39,941		15,832		40%
Other	20,706		11,276		9,430		84%
Total operating expense	$	366,169	$	365,656
Average costs per Mcfe
Lease operating and workover	$	0.49	$	0.46	$	0.03	7%
Taxes other than income	0.17		0.14		0.03		21%
Gathering and transportation costs	0.84		0.77		0.07		9%
Depreciation, depletion, amortization, and accretion	0.55		0.76		(0.21)		(28)%
General and administrative	0.39		0.27		0.12		44%
Other	0.15		0.08		0.07		88%
Total	$	2.59	$	2.48
*Percentage not meaningful

Lease Operating and Workover

The following table summarizes our components of lease operating expenses for the periods presented:


	Six Months Ended June 30,
	2025				2024				$ Change		% Change
(in thousands, other than percentages and average costs)	Amount		Per Mcfe		Amount		Per Mcfe
Lease operating expenses	$	66,352	$	0.47	$	65,351	$	0.44	$	1,001	2	%
Workover expenses	2,879		0.02		3,289		0.02		(410)		(12)	%
Total lease operating and workover expense	$	69,231	$	0.49	$	68,640	$	0.46	$	591	1	%

Lease operating and workover expenses were $69.2 million, or $0.49 per Mcfe, for the six months ended June 30, 2025, which was an increase of approximately $0.6 million, or 1%, from $68.6 million, or $0.46 per Mcfe, for the six months ended June 30, 2024. The increase in lease operating and workover expenses during the six months ended June 30, 2025 compared to the same period in 2024 was due to our Pad of the Future activity in 2025 of $1.6 million and vehicle expenses of $0.7 million. In addition, during the six months ended June 30, 2024, we received a credit of $1.5 million for a water sharing agreement that related to 2023. This was offset by decreases in compression and water expenses of $1.8 million and materials and labor of $0.9 million, which were due to well shut ins and increased storms in the first quarter of 2025 resulting in a decrease in lease operating projects, and timing of inspection fees of $0.4 million.

Taxes Other Than Income

Taxes other than income were $23.6 million, or $0.17 per Mcfe, for the six months ended June 30, 2025, which was an increase of approximately $2.4 million, or 11%, from $21.2 million, or $0.14 per Mcfe, for the six months ended June 30, 2024. The increase in taxes other than income during the six months ended June 30, 2025 compared to 2024 was due to increases in production taxes of $8.2 million in the Barnett. This was offset by decreases in ad valorem and property taxes associated with our operations in the Barnett and NEPA of $5.7 million and $0.1 million, respectively. Certain ad valorem and production taxes are not applicable to our NEPA properties.


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Gathering and Transportation

Gathering and transportation expenses were $118.8 million, or $0.84 per Mcfe, for the six months ended June 30, 2025, which was an increase of approximately $5.7 million, or 5%, from $113.1 million, or $0.77 per Mcfe, for the six months ended June 30, 2024. This increase was primarily driven by natural gas and NGL rate increases of $5.0 million and $1.4 million, respectively, and increased natural gas production of $0.4 million. This was offset by NGL production decreases of $0.7 million and gathering costs associated with our midstream business of $0.4 million.

Depreciation, Depletion, Amortization, and Accretion

Depreciation, depletion, amortization, and accretion was $78.0 million, or $0.55 per Mcfe, for the six months ended June 30, 2025, which was a decrease of approximately $33.5 million, or 30%, from $111.5 million, or $0.76 per Mcfe, for the six months ended June 30, 2024. The decrease in depreciation, depletion, amortization, and accretion during the six months ended June 30, 2025 compared to the six months ended June 30, 2024 was primarily due to a depletion rate adjustment in 2025, which was driven by higher reserves.

General and Administrative

General and administrative expenses were $55.8 million, or $0.39 per Mcfe, for the six months ended June 30, 2025, which was an increase of approximately $15.8 million, or 40%, from $39.9 million, or $0.27 per Mcfe, for the six months ended June 30, 2024. The increase in general and administrative expenses during the six months ended June 30, 2025 compared to the six months ended June 30, 2024 was due to increases from Company-wide growth initiatives of $8.9 million in contract labor, employee-based compensation, and employee expenses, $4.6 million in consulting and information technology-related expenses, and $2.3 million in severance costs.

Other Operating Expenses

Other operating expenses were $20.7 million, or $0.15 per Mcfe, for the six months ended June 30, 2025, which was an increase of approximately $9.4 million, or 84%, from $11.3 million, or 0.08 per Mcfe, for the six months ended June 30, 2024. The increase in other operating expenses during the six months ended June 30, 2025 compared to the same period in 2024 was due to an increase of $3.7 million in gas purchases due to increased volumes and natural gas prices, $3.1 million of costs related to the CCUS equity raise, $2.3 million in CCUS transaction fees, $2.1 million of a deficiency payment incurred under our minimum volume commitments on our midstream pipeline, $1.5 million in project write-offs, and $0.8 million in legal settlements. This was offset by $5.0 of accrued waste emissions costs established by the Inflation Reduction Act recognized during the six months ended June 30, 2024, which were not accrued in 2025 due to the impacts of the new Trump Administration.

Other Income (Expense)

Gains (losses) on contingent consideration liabilities. For the six months ended June 30, 2024, we recognized a gain on contingent consideration liabilities accruing as an earnout obligation under the purchase agreements executed in connection with the Devon Barnett Acquisition and the Exxon Barnett Acquisition. The gain on contingent consideration liabilities was $6.1 million for the six months ended June 30, 2024, and consisted of a gain of $3.9 million and a gain of $2.2 million from the Devon Barnett Acquisition and the Exxon Barnett Acquisition, respectively. The contingent considerations under these purchase agreements expired in 2024.

Earnings (losses) from equity affiliate. Losses from our equity affiliate was $0.5 million for the six months ended June 30, 2025, which was a decrease in losses of $22.5 million, from $23.0 million for the six months ended June 30, 2024. Losses from our equity affiliate is related to our investment in, and our proportionate share in the income or losses of the Power Joint Venture.

Interest expense. Interest expense was $10.5 million for the six months ended June 30, 2025, which was a decrease of $20.7 million, from $31.2 million for the six months ended June 30, 2024. The decrease in interest expense during the six months ended June 30, 2025 was primarily due to lower interest rates on our RBL Credit Facility, which we entered into on June 11, 2024, and subsequently paid down the outstanding balances on our SCB Credit Facility, the Revolving Credit Agreement, and the Term Loan Credit Agreement, which incurred higher interest rates.

Interest expense, related party. Interest expense from our related party borrowings with BNAC was $3.9 million for the six months ended June 30, 2024, which was paid down in June 2024.

Interest income. Interest income was $0.3 million for the six months ended June 30, 2025, which was a decrease of $3.1 million, from $3.4 million for the six months ended June 30, 2024. The decrease was due to the cessation of interest earned on


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restricted cash following the repayment of the Term Loan Agreement in June 2024, which had previously funded the debt service reserve account.

Income tax benefit (expense). For the six months ended June 30, 2025, we had an income tax benefit of $1.3 million, which was a change of $40.1 million, from $41.4 million income tax benefit for the six months ended June 30, 2024. The period-over-period change was primarily due to a pre-tax income for the six months ended June 30, 2025 compared to a pre-tax loss for the six months ended June 30, 2024.

Liquidity and Capital Resources

Capital Commitments

Our primary needs for cash are to fund our upstream development, midstream, power, and CCUS activities, fund operations and capital expenditures, acquisitions, and asset retirement obligations, cover any debt interest or minimum volume commitment obligations, pay down debt, and return capital to stockholders. Our primary use of cash during the six months ended June 30, 2025 and 2024 was to fund the development of our natural gas properties.

During the six months ended June 30, 2025 and 2024, cash paid for capital expenditures was $123.7 million and $31.6 million, respectively. Our current estimated budget for accrued capital expenditures in 2025 is approximately $290 million to $350 million. Capital expenditures for our operated properties are largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for natural gas and NGLs, the availability of equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs, and the level of participation by other interest owners. We will continue to monitor commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions.

Capital Resources

Historically, our primary sources of capital and liquidity have consisted of internally generated cash flows from operations, together with loans and capital contributions from our majority stockholder, BNAC. We also enter into financial instruments to reduce the impact of commodity price volatility and provide a level of certainty and stability around cash flows. We currently believe that our cash flows from operations, cash on hand, borrowings under our RBL Credit Agreement, and our commodity hedges in place will provide sufficient liquidity to fund our operations and our capital expenditures for the remainder of 2025, excluding our CCUS business. We expect to fund the majority of our CCUS business from a variety of external sources, which may include contributions from our joint venture with the Class B Member, project-based equity partnerships, debt financing, and federal grants, with the remaining capital needs being funded with cash flows from operations.

The following table summarizes our cash flows for the six months ended June 30, 2025 and 2024 (in thousands):


	Six Months Ended June 30,
	2025		2024

Net cash provided by operating activities	$	98,783	$	9,782
Net cash provided by (used in) investing activities	(129,654)		101,633
Net cash provided by (used in) financing activities	37,429		(267,287)
Net increase (decrease) in cash, cash equivalents, and restricted cash	$	6,558	$	(155,872)

Cash flows provided by operating activities. Net cash provided by operating activities was $98.8 million for the six months ended June 30, 2025, compared to $9.8 million for the six months ended June 30, 2024. Net cash provided by operating activities increased during the six months ended June 30, 2025 compared to the six months ended June 30, 2024 due to a $48.3 million increase in working capital, a $43.9 million increase in income from operations (excluding net unrealized gains (losses), depreciation, depletion, amortization, and accretion, equity-based compensation, and impairment of asset held for sale), resulting from higher natural gas prices in 2025 compared to 2024, a $35.4 million decrease in cash paid for interest, and $3.9 million in transaction costs paid in June 2024. These increases were offset by cash received in January 2024 for the sale of call options of $23.5 million, cash paid in February 2025 for the purchase of put options of $16.2 million, and lower interest income of $3.1 million.


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Operating cash flow fluctuations are substantially driven by realized commodity prices, production volumes, and operating expenses. Prices for natural gas and NGLs have historically been volatile, primarily as a result of supply and demand, pipeline infrastructure constraints, basis differentials, inventory storage levels, and seasonal influences. We are unable to predict future commodity prices and therefore cannot provide assurance about future levels of cash provided by operating activities.

Cash flows provided by (used in) investing activities. Net cash used in investing activities was $129.7 million for the six months ended June 30, 2025, compared to net cash provided by investing activities of $101.6 million for the six months ended June 30, 2024. The change was due to the increase of $95.1 million of capital expenditures (excluding CCUS activities) and a deposit on fixed asset purchase of $7.5 million for the six months ended June 30, 2025 compared to the six months ended June 30, 2024. This was offset by the decrease of $3.0 million of expenditures on CCUS activities over the same period. Contributing to the cash inflow during the six months ended June 30, 2024 were the proceeds from the sale of Chaffee and Chelsea of $106.7 million and $25.0 million, respectively.

The following table presents our capital expenditures (excluding leasehold costs and acquisitions) on an accrual basis for the six months ended June 30, 2025 and 2024 and reconciles to cash flows used for capital expenditures in the condensed consolidated statements of cash flows.


	Six Months Ended June 30,
	2025		2024
Total use of cash and cash equivalents for capital expenditures	$	(123,669)	$	(31,608)
Increase in accrued capital expenditures	(13,105)		(1,296)
Capital expenditures (accrued)	$	(136,774)	$	(32,904)

Cash flows provided by (used in) financing activities. Net cash provided by financing activities was $37.4 million for the six months ended June 30, 2025, which consisted of net borrowings on debt of $35.0 million and cash contributions from noncontrolling interest of $4.4 million, which was offset by payments of $1.2 million for taxes related to net share settlement of restricted stock units and $0.7 million of debt issuance costs. For the six months ended June 30, 2024, cash outflows were due to net payments on debt of $248.0 million, debt extinguishment costs of $10.2 million for the early retirement of the Term Loan Credit Agreement and the Revolving Credit Agreement, and $8.1 million of debt issuance costs on the RBL Credit Agreement.

Working Capital

As of June 30, 2025, we had cash and cash equivalents of $21.4 million, compared to $14.9 million of cash and cash equivalents as of December 31, 2024. Our net working capital deficit was $76.3 million as of June 30, 2025, compared to a deficit of $71.6 million as of December 31, 2024.

Our working capital fluctuates based on the timing of cash collections on accounts receivable and payments on accounts payable. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Furthermore, we expect that our pace of development, production volumes, commodity prices, and differentials to NYMEX pricing for our natural gas and oil production will be the largest variables impacting our working capital.

RBL Credit Agreement

On June 11, 2024, BKV Corporation, as guarantor, and BKV Upstream Midstream, as borrower, entered into the RBL Credit Agreement with Citibank, N.A., as the administrative agent, and the financial institutions party thereto. The RBL Credit Agreement includes a maximum credit commitment of $1.5 billion. On May 6, 2025, with the unanimous consent of our credit facility lenders, we amended the RBL Credit Agreement to, among other things, increase the borrowing base by $100.0 million and the elected commitment by $65.0 million. This amendment constituted the semiannual borrowing base redetermination. As of June 30, 2025, the RBL Credit Agreement had a borrowing base of $850.0 million, an elected commitment of $665.0 million, and the ability to issue up to $40.0 million in letters of credit. The loans may be borrowed, repaid, and reborrowed during the term of the RBL Credit Agreement. The RBL Credit Agreement will mature on June 12, 2028. The obligations under the RBL Credit Agreement are secured and guaranteed on a secured basis by BKV Upstream Midstream and all of BKV Upstream Midstream’s current and future material restricted subsidiaries. Loans under the RBL Credit Agreement bear interest at one, three, or six-month term SOFR or ABR, as applicable, plus a credit spread adjustment of 0.10% for SOFR borrowings, plus an applicable margin per annum. Interest is payable on the last day of each interest period and at maturity. We are obligated to pay certain fees to the lenders and administrative agent under the RBL Credit Agreement, including commitment fees on the average daily amount of the


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undrawn portion of the commitments. As of August 12, 2025, $282.0 million of revolving borrowings and $14.1 million of letters of credit were outstanding under the RBL Credit Agreement, leaving $368.9 million of available capacity thereunder for future borrowings and letters of credit.

The RBL Credit Agreement contains various restrictive covenants that, among other things, limit BKV Upstream Midstream’s ability and the ability of its restricted subsidiaries to, subject to certain exceptions: (i) incur indebtedness; (ii) incur liens; (iii) acquire or merge with any other company; (iv) sell assets or equity interests of their subsidiaries; (v) make investments; (vi) pay dividends or make other restricted payments; (vii) change their lines of business; (viii) enter into certain hedge agreements; (ix) enter into transactions with affiliates; (x) own any subsidiary that is not organized in the United States; (xi) prepay any unsecured senior or subordinated indebtedness; (xii) engage in certain marketing activities; and (xiii) allow, on a net basis, gas imbalances, take-or-pay or other prepayments with respect to their proved oil and gas properties.

Beginning with the fiscal quarter ending September 30, 2024, the RBL Credit Agreement requires BKV Upstream Midstream and its restricted subsidiaries to always hedge not less than 50% of projected production from their proved developed producing reserves for the subsequent 24 calendar month period immediately following such required delivery date.

The RBL Credit Agreement also includes financial covenants that require BKV Upstream Midstream to maintain:

•on a quarterly basis, a minimum Current Ratio (as defined in the RBL Credit Agreement) of no less than 1.00 to 1.00; and

•on a quarterly basis, a Net Leverage Ratio (as defined in the RBL Credit Agreement) of no greater than 3.25 to 1.00.

The RBL Credit Agreement includes customary equity cure rights that will enable us to cure certain breaches of the minimum current ratio covenant or the maximum net leverage ratio covenant.

BKV-BPP Power and BKV-BPP Cotton Cove Joint Ventures

Under the terms of the BKV-BPP Power LLC Agreement and BKV-BPP Cotton Cove LLC Agreement, we do not have the ability to unilaterally cause BKV-BPP Power or BKV-BPP Cotton Cove to make distributions. During the six months ended June 30, 2025 and 2024, no distributions were made by BKV-BPP Power or BKV-BPP Cotton Cove. In addition, we may be required to make additional capital contributions to one or both joint ventures to fund items approved in their respective annual budgets or other matters approved by their respective boards. Such additional capital contributions, which are not subject to any limit on the potential amount required, would reduce the amount of cash otherwise available to us. However, any additional capital contributions to BKV-BPP Power must be approved by a majority of BKV-BPP Power's ten member board of managers, five of whom are appointed by us and five of whom are appointed by BPPUS. Similarly, any additional capital contributions to BKV-BPP Cotton Cove must receive the unanimous approval of BKV-BPP Cotton Cove, LLC's six member board of managers, four of whom are appointed by us and two of whom are appointed by BPPUS.

Off-Balance Sheet Arrangements

We may enter into off-balance sheet arrangements and transactions that could give rise to material off-balance sheet arrangements. As of June 30, 2025, our material off-balance sheet arrangements and transactions included volume commitments of $287.6 million and letters of credit of $14.1 million against the RBL Credit Agreement. For further information regarding these arrangements, see Note 11 - Commitments and Contingencies to our condensed consolidated financial statements and under “—Loan Agreements and Credit Facilities — RBL Credit Agreement.”

Critical Accounting Policies and Estimates

Management’s discussion and analysis of our financial condition and results of operations are based upon our historical consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain


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assets, liabilities, and related disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

Accounting for the BKV-CIP Joint Venture

As described in Note 10 - Investment in the BKV-CIP Joint Venture in our condensed consolidated financial statements, on May 8, 2025, BKV dCarbon Ventures, together with C Squared Solutions, Inc., a subsidiary of the Energy Transition Fund managed by Copenhagen Infrastructure Partners (CIP), and for the limited purposes specified therein, BKV Corporation, entered into the BKV-CIP JV Agreement forming the BKV-CIP Joint Venture. We consider the BKV-CIP Joint Venture a variable interest entity (“VIE”) of BKV in accordance with ASC 810, Consolidation as BKV is deemed to be the primary beneficiary of the joint venture. Generally, a VIE is an entity with at least one of the following conditions: (i) the total equity investment at risk is insufficient to allow the entity to finance its activities without additional subordinated financial support, or (ii) the holders of the equity investment at risk, as a group, lack the characteristics of having a controlling financial interest. The primary beneficiary of a VIE is an entity that has a variable interest or a combination of variable interests that provide such entity with a controlling financial interest in the VIE. An entity is deemed to have a controlling financial interest in a VIE if it has both of the following characteristics: (i) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance, and (ii) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE.

In exchange for cash contributions received from the Class B Member to the BKV-CIP Joint Venture, the BKV-CIP Joint Venture has issued 435,250 Class B Units (the “Class B Units”) at $10.00 per unit as of June 30, 2025. We determined that the Class B Units should be classified as noncontrolling interest within mezzanine equity on the Company's condensed consolidated balance sheets. The Class B Units are not mandatorily redeemable or currently redeemable, but become exercisable with the passage of time, which is on the second anniversary of the BKV-CIP JV Agreement, or May 8, 2027. Prior to the second anniversary, we determined that there is an embedded put option in the Class B Units, which does not meet the derivative accounting criteria, and is not within control of the Company. Therefore, the shares of the Class B Units have been classified as noncontrolling interest within mezzanine equity on our condensed consolidated balance sheets. The Class B Units also have a multiple investment on capital equal to 1.65, which may be redeemed on the second anniversary date. The contributions from the Class B Member are accreted to the redemption value over a 2-year period (using the effective interest method) with the accretion accounted for as a dividend paid to the Class B Member.

Tariffs and Trading Relationships

In April 2025, the U.S. government announced a baseline tariff of 10% on products imported from all countries and an additional individualized reciprocal tariff on the countries with which the United States has the largest trade deficits, including China. Increased tariffs by the United States have led and may continue to lead to the imposition of retaliatory tariffs by foreign jurisdictions. Additionally, the U.S. government has announced and rescinded multiple tariffs on several foreign jurisdictions, which has increased uncertainty regarding the ultimate effect of the tariffs on economic conditions. Current uncertainties about tariffs and their effects on trading relationships may impact the demand for, and price of natural gas, NGLs, and oil, increase the costs of goods and services or the availability of raw materials that we rely on to operate our business or impact interest rates. Although we are continuing to monitor the economic effects of such announcements, as well as opportunities to mitigate their related impacts, costs and other effects associated with the tariffs remain uncertain and could adversely impact our financial position, results of operations, and liquidity.

Emerging Growth Company Status

We are an “emerging growth company” as defined in Section 2(a)(19) of the Securities Act of 1933, as amended, including as modified by the Jumpstart Our Business Startups of 2012 (the “JOBS Act”). As a result, for so long as we qualify as an emerging growth company, we are eligible to take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies. We have elected to take advantage of certain of the reduced disclosure obligations in this Quarterly Report on Form 10-Q and may elect to take advantage of other reduced reporting requirements in our future filings with the SEC. As a result, the information that we provide to our stockholders may be different from other public reporting companies.

Under the JOBS Act, emerging growth companies can delay adopting new or revised accounting standards issued subsequent to the enactment of the JOBS Act, until such time as those standards apply to private companies. However, we have irrevocably elected not to avail ourselves of this exemption. Rather, we will adopt new or revised accounting standards on the relevant dates in which adoption of such standards is required for other public companies.


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We may take advantage of these provisions until the last day of our fiscal year following the fifth anniversary of the date of our IPO. Such fifth anniversary will occur in 2029. However, if certain events occur prior to the end of such five-year period, including if we become a “large accelerated filer,” our gross revenues for any fiscal year equal or exceed $1.235 billion or we issue more than $1.0 billion of non-convertible debt in any three-year period, we will cease to be an emerging growth company prior to the end of such five-year period.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

There has been no material change in our market risks since December 31, 2024, as set forth in our 2024 Annual Report on Form 10-K.

Commodity Price Risk and Hedging Activities

Our primary market risk exposure is in the price we receive for our natural gas and NGL production. Pricing is primarily driven by spot regional market prices applicable to our U.S. natural gas production. Pricing for natural gas and NGLs has historically been volatile and unpredictable, and we expect this volatility to continue in the future. The prices we receive for our production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.

To mitigate some of the potential negative impact on our cash flows caused by changes in commodity prices, we enter into financial derivative instruments for a portion of our natural gas and NGL production when management believes that favorable future prices can be secured.

Our financial hedging activities are intended to support natural gas and NGL prices at targeted levels and to manage our exposure to natural gas and NGL price fluctuations. These contracts may include commodity price swaps, whereby we will receive a fixed price and pay a variable market price to the contract counterparty, producer collars that set a floor and ceiling price for the hedged production, or basis differential swaps. These contracts are financial instruments and do not require or allow for physical delivery of the hedged commodity. The derivative contracts outstanding as of June 30, 2025 consisted of commodity price swaps, basis differential swaps, put and call options, and producer collar agreements, subject to master netting agreements with each individual counterparty.

These derivative contracts cover portions of our projected positions through 2027. Our commodity hedge position as of June 30, 2025 is summarized in Note 5 - Derivative Instruments to our condensed consolidated financial statements.

We may enter into single hedge transactions with settlements up to 48 months. The aggregation of these executed hedge instruments may not exceed 60% without board of director approval of our forecasted production volumes for the current year and subsequent year, and for up to 40% and 25% of our forecasted production volumes in each of the respective subsequent years thereafter. During the six months ended June 30, 2025 and 2024, a hypothetical increase or decrease of $0.10 per Mcf in NYMEX would have resulted in a $7.0 million and $4.2 million decrease or increase in natural gas hedge revenues, respectively, and a hypothetical increase or decrease of $1.00 per Bbl of NGL purity product price would have resulted in a $2.7 million and $3.0 million decrease or increase in NGL hedge revenues, respectively.

Additionally, to reduce its exposure to fluctuations in the market price of electricity and natural gas, BKV-BPP Power enters into financially settled HRCOs, which are contracts for the financial purchase and sale of power based on a floating price of natural gas at a predetermined location using a predetermined conversion factor, or heat rate, required to turn the fuel input into electricity. BKV-BPP Power is exposed to basis risk in its operations when its derivative contracts settle financially and it delivers physical electricity on different terms. For example, if BKV-BPP Power enters into an HRCO, it hedges its electricity production based on an agreed price for that electricity, but physical electricity must be delivered to delivery points in the market it serves. BKV-BPP Power is exposed to basis risk between the hub price specified in the HRCO and the price that it receives for the sales of physical electricity. BKV-BPP Power attempts to hedge basis risk where possible, but hedging instruments are sometimes not economically feasible or available in the quantities that it requires. BKV-BPP Power’s hedging activities do not provide it with protection for all of its basis risk and could result in economic losses and liabilities, which could have a material adverse effect on BKV-BPP Power, and thus on our business, financial condition, results of operations, and cash flows. Additionally, by using derivative instruments to economically hedge exposure to changes in power prices, we could limit the benefit we would receive from increases in the power prices, which could have an adverse effect on our financial condition. Moreover, in the event BKV-BPP Power is not able to satisfy its obligations under the HRCO, it must purchase power at prevailing market prices to satisfy the HRCO. Likewise, increases in power pricing could limit the benefit we receive under HRCOs and may result in losses. Either


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such event could have a material adverse effect on BKV-BPP Power, and thus on our business, financial condition, results of operations, and cash flows.

All derivative instruments, other than those that meet the normal purchase and normal sale scope exception, are recorded at fair market value in accordance with GAAP and are included in our condensed consolidated balance sheets as assets or liabilities. The fair values of our derivative instruments are adjusted for non-performance risk. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment; therefore, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our condensed consolidated statements of operations. We present total gains or losses on commodity derivatives (for both settled derivatives and derivative positions which remain open) within operating revenues as derivative gains (losses), net.

Mark-to-market adjustments of derivative instruments cause earnings volatility but have no cash flow impact relative to changes in market prices until the derivative contracts are settled or monetized prior to settlement. We expect continued volatility in the fair value of our derivative instruments. Our cash flows are only impacted when the associated derivative contracts are settled or monetized by making or receiving payments to or from the counterparty. As of June 30, 2025, the estimated fair value of our commodity derivative instruments was a net liability of $82.5 million, comprised of current and noncurrent assets and current and noncurrent liabilities. As of December 31, 2024, the estimated fair value of our commodity derivative instruments was a net liability of $67.6 million, comprised of current and noncurrent liabilities.

By removing price volatility from a portion of our expected production through December 2027, we have mitigated, but not eliminated, the potential negative effects of changing prices on our operating cash flows for those periods. While mitigating the negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices above the fixed hedge prices.

Counterparty Credit Risk

We routinely monitor and manage our exposure to counterparty risk related to derivative contracts by requiring specific minimum credit standards for all counterparties, actively monitoring counterparties’ public credit ratings, and avoiding concentration of credit exposure by transacting with multiple counterparties. Our commodity derivative contract counterparties are typically financial institutions with investment-grade credit ratings.

We enter into International Swap Dealers Association (“ISDA”) Master Agreements with each of our derivative counterparties prior to executing derivative contracts. The terms of the ISDA Master Agreements provide, among other things, the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either us or counterparty to a derivative contract.

In addition, we utilize an unaffiliated third party to market all of our natural gas production to various purchasers, which consist of credit-worthy counterparties, including utilities, LNG producers, industrial consumers, major corporations, and super majors in our industry. We rely on the credit worthiness of such third party marketer, who collects directly from the purchasers and remits to us the total of all amounts collected on our behalf, less their fee for making such sales.

Interest Rate Risks

As of June 30, 2025, our primary exposure to interest rate risk resulted from our $200.0 million of outstanding borrowings on our RBL Credit Agreement, which has a floating interest rate. As of June 30, 2024, our primary exposure to interest rate risk resulted from our outstanding borrowings under our RBL Credit Agreement of $360.0 million and on our related party borrowings with BNAC of $50.0 million, both of which had floating interest rates. The average annualized interest rate incurred on our outstanding borrowings during the six months ended June 30, 2025 and 2024 was approximately 7.4% and 9.4%, respectively. We estimate that a 1.0% increase in the applicable average interest rates during the six months ended June 30, 2025 and 2024 would have resulted in increases of $1.1 million and $3.4 million in interest expense, respectively.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As required by Rules 13a-15(b) and 15d-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of the end of the period covered by this Quarterly Report on Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in the reports that we file or submit under the


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Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the Commission's rules and forms, and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that due to the presence of our material weakness described below, as of June 30, 2025, our disclosure controls and procedures were not effective.

Material Weakness in Internal Control over Financial Reporting

As of June 30, 2025, a material weakness continued to exist in our internal control over financial reporting. A “material weakness” is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

We did not design and maintain effective controls related to the accounting for income taxes, which were not designed at a sufficient level of precision or rigor to prepare and review the tax rate reconciliation, return to provision, income tax provision, related income tax assets and liabilities, and disclosures in the consolidated financial statements. This material weakness resulted in (i) audit adjustments to income tax benefit, income taxes payable to related party, and deferred tax assets and liabilities in the consolidated financial statements as of December 31, 2021 and for the year then ended, (ii) an immaterial audit adjustment to the supplemental cash flow information for cash payments for income taxes and a reclassification between oil and gas production and other taxes payable and other accrued liabilities within Note 11 - Accounts Payable and Accrued Liabilities to our consolidated financial statements as of and for the year ended December 31, 2023, (iii) audit adjustments to deferred tax liabilities and additional paid-in capital as of December 31, 2024, and (iv), the revision of our previously issued financial statements for the interim and annual periods included in the years ended December 31, 2021, 2022, and 2023, and interim periods included in the year ended December 31, 2024. This material weakness could result in a misstatement of the aforementioned account balances or disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected.

Notwithstanding this material weakness, we believe our condensed consolidated financial statements fairly present, in all material respects, our financial condition, results of operations, and cash flows for the periods presented, in accordance with GAAP.

Remediation Efforts to Address the Material Weakness

We have taken steps towards remediating this material weakness primarily by designing and implementing additional internal controls, including those related to the preparation and review of the income tax rate reconciliation, return to provision, income tax provision, related income tax assets and liabilities, and income tax disclosures. Although we believe we are addressing the internal control deficiencies that led to this material weakness, the measures we have taken, and plan to take, may not be effective.

Inherent Limitations on Effectiveness of Controls and Procedures

In designing and evaluating the disclosure controls and procedures and internal control over financial reporting, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures and internal control over financial reporting must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

Changes in Internal Control over Financial Reporting

There were no changes in the Company's internal control over financial reporting during the quarter ended June 30, 2025 that have materially affected, or are reasonably likely to materially affect our internal controls over financial reporting.


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PART II OTHER INFORMATION

Item 1. Legal Proceedings

This information is set forth in Part I, Item 1 in Note 11 - Commitments and Contingencies to the condensed consolidated financial statements incorporated herein.

Item 1A. Risk Factors

The Quarterly Report on Form 10-Q should be read in conjunction with the “Risk Factors” disclosed in our 2024 Annual Report on Form 10-K, which could materially affect our business, financial condition, or future results. Except as set forth below, there have been no material changes to the risk factors previously disclosed in the 2024 Annual Report on Form 10-K.

The consummation of the Bedrock acquisition is subject to a number of conditions that may not be satisfied or completed on a timely basis or at all. Accordingly, there can be no assurance as to when or if the Bedrock acquisition will be completed, and the failure to complete the Bedrock acquisition could have a material and adverse effect on our business, financial condition, results of operations and cash flows.

Although we expect to complete the Bedrock acquisition late in the third quarter or early in the fourth quarter of 2025, there can be no assurances as to the exact timing of the closing or that the Bedrock acquisition will be completed at all. The consummation of the Bedrock acquisition is subject to the satisfaction or waiver of a number of conditions contained in the related membership interest purchase agreement. Such conditions, some of which are beyond our control, may not be satisfied or waived in a timely manner or at all and therefore make the completion and timing of the Bedrock acquisition uncertain. In addition, the membership interest purchase agreement contains certain termination rights for both parties, which if exercised will also result in the Bedrock acquisition not being consummated. Any such termination or any failure to otherwise complete the Bedrock acquisition could result in various consequences, including, among others: our business being adversely impacted by the failure to pursue other beneficial opportunities due to the time and resources committed by our management to the Bedrock acquisition, without realizing any of the benefits of completing the Bedrock acquisition; being required to pay our legal, accounting and other expenses relating to the Bedrock acquisition; the market price of our common stock being adversely impacted to the extent that the current market price reflects a market assumption that the Bedrock acquisition will be completed; and negative reactions from the financial markets and customers that may occur if the anticipated benefits of the Bedrock acquisition are not realized. Such consequences could materially and adversely affect our business, financial condition, results of operations and cash flows.

Even if the Bedrock acquisition is completed, we may be unable to successfully integrate Bedrock’s business into our business or achieve the anticipated benefits of the Bedrock acquisition.

The success of the Bedrock acquisition will depend, in part, on our ability to realize the anticipated benefits and cost savings from integrating the assets and operations of Bedrock into our business, and there can be no assurance that we will be able to successfully integrate or otherwise realize the anticipated benefits of the Bedrock acquisition. Difficulties in integrating Bedrock into our company and our ability to manage the combined company may result in us performing differently than expected, in operational challenges or in the delay or failure to realize anticipated expense-related efficiencies and could have a material adverse effect on our business, financial condition, results of operations and cash flows. Potential difficulties that may be encountered in the integration process include, among others:

•the inability to successfully integrate Bedrock operationally, in a manner that permits us to achieve the full revenue, expected cash flows and cost savings anticipated from the Bedrock acquisition;

•not realizing anticipated operating synergies; and

•potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the Bedrock acquisition.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None

Item 3. Defaults Upon Senior Securities

None

Item 4. Mine Safety Disclosures


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None

Item 5. Other Information

Securities Trading Plans of Directors and Executive Officers

During the three months ended June 30, 2025, no director or officer of the Company (as defined in Rule 16a-1(f) of the Exchange Act), adopted, modified, or terminated a “Rule 10b5-1 trading arrangement” or a “non-Rule 10b5-1 trading agreement” (each as defined in Item 408(a) of Regulation S-K).


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Item 6. Exhibits

Incorporated by Reference

Exhibit Number

Description

Form

SEC File Number

Exhibit

Filing Date

Filed or Furnished Herewith

3.1

Second Amended and Restated Certificate of Incorporation of BKV Corporation.

8-K

001-42282

3.1

9/27/24

3.2

Second Amended and Restated Bylaws of BKV Corporation.

8-K

001-42282

3.2

9/27/24

10.1

Second Amendment to Credit Agreement, dated as of May 6, 2025 among BKV Corporation, BKV Upstream Midstream, LLC, Citibank, N.A., and the Lenders party thereto.

10-Q

001-42282

10.1

5/9/25

10.2 †

L imited Li ability Compan y Agreement of BKV dCarbon Project, LLC dated as of May 8, 2025 by BKV dCarbon Ventures, LLC and C Squared Solutions, Inc. and for t he limited purposes specified h erein, BKV C orporation.

31.1

Certification of Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification of Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS

Inline XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema Document.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB

XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document.

104

Cover Page Interactive Data File (embedded within the inline XBRL document).

† Portions of this exhibit (indicated by asterisks) have been redacted in compliance with Regulation S-K Item 601(b)(10)(iv). Additionally, annexes, schedules and certain exhibits have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The Company hereby undertakes to furnish supplemental copies of any of the omitted annexes, schedules and exhibits upon request by the SEC.


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Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	BKV Corporation


August 12, 2025	By:	/s/ David R. Tameron
		David R. Tameron
		Chief Financial Officer


	BKV Corporation


August 12, 2025	By:	/s/ Barry S. Turcotte
		Barry S. Turcotte
		Chief Accounting Officer


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Form: 10-Q

Documents